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This information is available in alternate format. Call Michelle Waters-Ekanem, Diversity Director, at 617-292-5751. TDD# 1-866-539-7622 or 1-617-574-6868 MassDEP Website: www.mass.gov/dep Printed on Recycled Paper Date Stamped: September 9, 2013 Mr. Scott G. Silverstein Footprint Power Salem Harbor Development LP 1140 Route 22 East, Suite 303 Bridgewater, NJ 08807 RE: SALEM Transmittal No.: X254064 Application No.: NE-12-022 Class: OP119 FMF No. PROPOSED AIR QUALITY PLAN APPROVAL Dear Mr. Silverstein: The Massachusetts Department of Environmental Protection (MassDEP), Bureau of Waste Prevention, has reviewed your Major Comprehensive Plan Application (Application) listed above, dated December 21, 2012. The Application was supplemented with amendments thereto dated April 12, 2013, June 10, 2013, June 18, 2013, August 6, 2013, August 20, 2013, September 4, 2013, and September 9, 2013. This Application concerns the proposed construction and operation of a 630 megawatt (MW) nominal combined cycle electric generating facility (the proposed Facility) to be located at 24 Fort Avenue in Salem, Massachusetts, the location of your existing power generating facility (Salem Harbor Station). With duct firing under summer conditions, the proposed Facility will be capable of generating an additional 62 MW, for a total of 692 MW. The Application bears the seal and signature of George S. Lipka, P.E., Massachusetts Registered Professional Engineer number 29704. This Application was submitted in accordance with 310 CMR 7.02 Plan Approval and Emission Limitations as contained in 310 CMR 7.00 “Air Pollution Control” regulations adopted by MassDEP pursuant to the authority granted by Massachusetts General Laws, Chapter 111, Section 142 A-J, Chapter 21C, Section 4 and 6, and Chapter 21E, Section 6. MassDEP’s review of your Application has been limited to air pollution control regulation compliance and does not relieve you of the obligation to comply with any other regulatory requirements. MassDEP has determined that the Application is administratively and technically complete and that the Application is in conformance with the Air Pollution Control regulations and current air pollution control engineering practice, and hereby grants this Proposed Plan Approval for said Application, as submitted, subject to the conditions listed below. This Proposed Plan Approval combines and includes: the 310 CMR 7.02 Comprehensive Plan Approval and 310 CMR 7.00: Appendix A Emission Offsets and Nonattainment Review Approval. This Proposed Plan Approval allows for construction and
Transcript
Page 1: Date Stamped: September 9, 2013yosemite.epa.gov › oa › eab_web_docket.nsf › Attachments By Parent… · Agency (EPA) Region 1 administered the PSD Program in Massachusetts.

This information is available in alternate format. Call Michelle Waters-Ekanem, Diversity Director, at 617-292-5751. TDD# 1-866-539-7622 or 1-617-574-6868 MassDEP Website: www.mass.gov/dep

Printed on Recycled Paper

Date Stamped: September 9, 2013

Mr. Scott G. Silverstein

Footprint Power Salem Harbor

Development LP

1140 Route 22 East, Suite 303

Bridgewater, NJ 08807

RE: SALEM

Transmittal No.: X254064

Application No.: NE-12-022

Class: OP119

FMF No.

PROPOSED AIR QUALITY PLAN

APPROVAL

Dear Mr. Silverstein:

The Massachusetts Department of Environmental Protection (MassDEP), Bureau of

Waste Prevention, has reviewed your Major Comprehensive Plan Application (Application)

listed above, dated December 21, 2012. The Application was supplemented with amendments

thereto dated April 12, 2013, June 10, 2013, June 18, 2013, August 6, 2013, August 20, 2013,

September 4, 2013, and September 9, 2013. This Application concerns the proposed construction

and operation of a 630 megawatt (MW) nominal combined cycle electric generating facility (the

proposed Facility) to be located at 24 Fort Avenue in Salem, Massachusetts, the location of your

existing power generating facility (Salem Harbor Station). With duct firing under summer

conditions, the proposed Facility will be capable of generating an additional 62 MW, for a total

of 692 MW. The Application bears the seal and signature of George S. Lipka, P.E.,

Massachusetts Registered Professional Engineer number 29704.

This Application was submitted in accordance with 310 CMR 7.02 Plan Approval and

Emission Limitations as contained in 310 CMR 7.00 “Air Pollution Control” regulations adopted

by MassDEP pursuant to the authority granted by Massachusetts General Laws, Chapter 111,

Section 142 A-J, Chapter 21C, Section 4 and 6, and Chapter 21E, Section 6. MassDEP’s review

of your Application has been limited to air pollution control regulation compliance and does not

relieve you of the obligation to comply with any other regulatory requirements.

MassDEP has determined that the Application is administratively and technically

complete and that the Application is in conformance with the Air Pollution Control regulations

and current air pollution control engineering practice, and hereby grants this Proposed Plan

Approval for said Application, as submitted, subject to the conditions listed below.

This Proposed Plan Approval combines and includes: the 310 CMR 7.02

Comprehensive Plan Approval and 310 CMR 7.00: Appendix A Emission Offsets and

Nonattainment Review Approval. This Proposed Plan Approval allows for construction and

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 2 of 59

operation of the proposed Facility, and provides information on the proposed Facility

description, emission control systems, emissions limits, CEMS, COMS, monitoring/testing,

record keeping, and reporting requirements.

Between March 3, 2003 and April 11, 2011, the United States Environmental Protection

Agency (EPA) Region 1 administered the PSD Program in Massachusetts. Effective April 11,

2011, a Delegation Agreement between MassDEP and EPA Region 1 was finalized for MassDEP

to resume administration of the PSD Program in Massachusetts pursuant to 40 CFR 52.21 and

the terms of the Delegation Agreement. Therefore, MassDEP is concurrently issuing a separate

Draft PSD Permit for the above described Facility.

The Fact Sheet for the Draft PSD Permit is attached to this Proposed Plan Approval.

This Fact Sheet also explains MassDEP’s evaluation of Best Available Control Technology

(BACT) for emissions of pollutants subject to PSD review and air quality impacts. MassDEP

verified and concurs with the BACT and Lowest Achievable Emission Rate (LAER) analyses for

pollutants not subject to PSD review in the Permittee’s Application. The PSD Permit and the 310

CMR 7.02 Comprehensive Plan Approval process have the same review considerations for these

items for this Facility.

Please review the entire Proposed Plan Approval, as it stipulates the conditions with

which the Facility owner/operator (Permittee) must comply in order for the Facility to be

operated in compliance with this Plan Approval.

1. DESCRIPTION OF FACILITY AND APPLICATION

Footprint Power Salem Harbor Development LP (the Permittee) proposes to construct

and operate a nominal 630 Megawatt (MW) natural gas fired, quick start (capable of producing

300 MW within 10 minutes of startup) combined cycle electric generating facility (the proposed

Facility) at Salem Harbor Station. With duct firing under summer conditions, the Facility will be

capable of generating an additional 62 MW, for a total of 692 MW. Construction of the Facility

is scheduled to begin in June 2014 and continue for a period of approximately 23 months. The

Facility is expected to commence commercial operation in June 2016. The existing Salem

Harbor Station is comprised of four (4) steam electric generating units (Boiler Units 1, 2, 3, and

4). Boiler Units 1 and 2, 84 MW and 81 MW, respectively, and both primarily coal fired, were

removed from service on or prior to December 31, 2011. Boiler Unit 3, a 150 MW primarily

coal-fired unit, and Boiler Unit 4, a 440 MW primarily oil fired unit, are required to cease

operation, permanently shutdown, and be rendered inoperable no later than June 1, 2014 (see

Final Amended Emission Control Plan Approval, Application No. NE-12-003, Transmittal No.

X241756).

The proposed Facility will be constructed on approximately 20 acres in the northwestern

portion of the approximately 65 acre Salem Harbor Station site. The Salem Harbor Station site is

bordered by Fort Avenue and the South Essex Sewerage District (SESD) wastewater treatment

plant to the north; Salem Harbor and Cat Cove to the east and northeast; the Blaney Street Ferry

terminal and several mixed-use buildings to the southeast; and by Derby Street and Fort Avenue

to the west. Residential neighborhoods and the Bentley Elementary School are located to the

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 3 of 59

west across Fort Avenue and Derby Street. Terrain elevations rise gradually to the north, west,

and southwest, with elevations rising 200 feet or more within approximately 10 kilometers.

The proposed Facility will be configured as two emission units (EU1 and EU2) each

capable of operating independently in order to respond to ISO – New England (ISO – NE)

dispatch requirements. EU1 and EU2 each will include one General Electric (GE) Model 107F

Series 5 combustion turbine generator (CTG), one duct burner, one Heat Recovery Steam

Generator (HRSG), and one steam turbine generator (STG). EU1 and EU2 each will have a

nominal generating capacity of approximately 315 MW (346 MW with duct firing). EU1 and

EU2 shall each burn natural gas with a sulfur content that does not exceed 0.5 grains per 100

standard cubic feet (pipeline natural gas) only in the CTG and duct burner. Based on an ambient

temperature of 90 degrees Fahrenheit, each CTG/duct burner pair shall be restricted to a

maximum design firing rate of 2,449 million British thermal units per hour (MMBtu/hr), higher

heating value (HHV), in combination. EU1 and EU2 shall each be restricted to a maximum fuel

heat input of 18,888,480 MMBtu per twelve month rolling period.

Other auxiliary equipment at the Facility will include an 80 MMBtu/hr, HHV auxiliary

boiler (EU3), a 750 Kilowatt (KW) electrical output emergency engine/generator set (EU4), a

371 brake horsepower (bhp) fire pump engine (EU5), an aqueous NH3 storage tank, an auxiliary

cooling tower, a demineralized water tank, a fire protection service water tank, and generator

step-up (GSU) transformers.

EU3 shall be equipped with Ultra Low NOx burners and shall burn pipeline natural gas

only. EU3 shall be restricted to a maximum fuel heat input of 525,600 MMBtu per twelve month

rolling period and will primarily be used to provide steam needed for plant start-up if the

combustion turbines are off-line, but also to provide process steam for other plant equipment.

EU4 and EU5 shall each burn ultra low sulfur diesel (ULSD) fuel oil (with a sulfur

content that does not exceed 15 parts per million) only and will be required for backup electrical

power if no power is available internally or from the utility grid and for fire protection service,

respectively. EU4 and EU5 shall each be used for emergency purposes only and shall each be

restricted to no more than 300 hours of operation per twelve month rolling period.

During normal operating conditions, EU1 and EU2 shall each operate in combined cycle

mode only. The first stage in combined cycle mode involves combustion of natural gas in the

combustion turbine with Dry Low Oxides of Nitrogen (NOx) Combustors to produce thermal

energy that is converted into mechanical energy to drive the turbine compressor section as well

as the generator that produces electrical energy. Under periods of operation when more electrical

power is needed, evaporative coolers located at the inlet air assembly of each turbine are

employed to evaporate a water mist into the turbine inlet air in order to cool the inlet air to the

combustion turbine. Cooler inlet air is denser, and with higher mass flow of inlet air, the turbine

can fire more natural gas and therefore produce more electrical energy than it otherwise would

produce if the evaporative coolers were not in operation.

In the second stage of combined cycle mode, the hot exhaust gases, with temperatures in

excess of 1000 degrees Fahrenheit exiting the combustion turbine, pass through a three pressure

level HRSG, which uses the heat from these gases to produce steam. Each HRSG houses an

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 4 of 59

oxidation catalyst for carbon monoxide (CO) and volatile organic compounds (VOC) control,

followed by an ammonia (NH3) injection grid and selective catalytic reduction (SCR) catalyst for

control of NOx. The steam produced by the HRSG is then directed to the STG where heat energy

is extracted and converted to additional electrical energy. The exhaust gases exiting the

combustion turbine also contain sufficient oxygen to allow the placement of a supplemental

firing burner in the duct (duct burner) allowing the production of additional steam, which

increases electrical energy production in the STG. An air-cooled condenser (ACC) is used to

condense the steam exiting the steam turbine and return the water produced to the HRSG through

a system of pumps and control mechanisms. Efficiency is enhanced in this cycle by using reheat

systems as well as using waste steam to heat feed water in the HRSG, thereby improving overall

efficiency.

Overall energy efficiency at the proposed Facility will be further improved by reducing

the plant parasitic load. High efficiency exterior and industrial interior Light Emitting Diode

(LED) lighting will be used throughout the proposed Facility, including in the Administration

Building and Operations Center. The analysis provided by the Permittee shows that operational

energy savings in Watts of 30 percent and 38 percent are expected for exterior and industrial

interior lighting, respectively, when compared to standard lighting. Based on a total energy

savings of 248 MW-hours per year and the proposed Facility’s carbon dioxide (CO2) emission

rate of 825 pounds per MW-hour net to the grid, avoided CO2 emissions via usage of LED

lighting amount to 102.3 tons per year. Variable speed drives will be used for all ACC fan

motors and the primary boiler feed water pump and condensate pump motors. Piping and valves

to reduce pressure losses will be considered in the detailed plant design. The highest efficiency

commercially available transformers compatible for interconnection with the nearby National

Grid switchyard will be installed.

Continuous Emissions Monitoring Systems (CEMS) shall be installed on EU1 and EU2

to sample, analyze and record NOx, CO, and NH3 concentration levels, and the percentage of

oxygen (O2), in the exhaust gas from each of the two HRSG exhaust flues. Samples shall also be

taken in the turbine exhaust upstream of the SCR system in order to provide data to optimize

usage of the NH3 injection control systems. In addition, Continuous Opacity Monitoring Systems

(COMS) shall be installed in the stacks of EU1, EU2, and EU3 to monitor and record opacity.

Most of the proposed Facility’s power plant equipment will be housed in a building

structure that will be approximately 115,000 square feet. In addition, the Facility will include

areas within other buildings for administrative and operating staff, warehousing of parts and

consumables, and maintenance shops and equipment servicing. All of the operations at the

proposed Facility will be contained within these buildings or conducted behind screening to

minimize visual impacts.

The proposed Facility will interconnect with the National Grid transmission system at

two (2) locations within the existing National Grid switchyard located on site. One unit of the

proposed Facility will interconnect at the same location where the existing Boiler Unit 4 is

presently connected. The other unit of the proposed Facility will interconnect at a new circuit

breaker bay to be constructed within the existing National Grid switchyard.

Natural gas will be delivered to the site via a new pipeline owned and operated by

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 5 of 59

Algonquin Gas Transmission, a subsidiary of Spectra Energy (Spectra). The pressure, capacity,

and route of the new pipeline are still being developed by Spectra. Spectra will also construct an

on site natural gas metering station. Spectra will obtain all federal, state, and local approvals for

the above equipment, as necessary.

2. EMISSION OFFSETS AND NONATTAINMENT REVIEW

Review considerations with respect to 310 CMR 7.00: Appendix A Emission Offsets and

Nonattainment Review (Appendix A) are not part of the PSD Review Process and are therefore

not addressed in the Fact Sheet. Therefore, MassDEP’s evaluation of Emission Offsets and

Nonattainment Review for the construction of the proposed Facility is provided below.

Appendix A applies to a new major source or major modification of an existing major

source located in a non-attainment area; or that is major for NOx or VOC emissions. With respect

to NOx and/or VOC emissions, Appendix A applies for a new major source of fifty (50) or more

tons per year or a major modification of an existing major source amounting to an increase of

twenty five (25) or more tons per year. Appendix A requires new major sources, or major

modifications thereat, to meet Lowest Achievable Emission Rate (LAER) and to obtain emission

offsets at a ratio of 1.20 to 1, plus a five (5) percent set aside that must be held and can neither be

sold nor used elsewhere. This yields an overall offset ratio of 1.26 to 1. LAER is defined in

Appendix A as the more stringent rate of emissions of: (a) the most stringent emissions

limitation which is contained in any State Implementation Plan (SIP) for such class or category

of stationary source, unless the owner or operator of the proposed stationary source demonstrates

that such limitations are not achievable; or, (b) the most stringent emissions limitation which is

achieved in practice by such class or category of stationary source.

The proposed Facility is expected to commence commercial operation in June 2016. The

proposed Facility shall be restricted to 144.8 and 28.0 tons per year of NOx and VOC emissions,

respectively. Therefore, the proposed Facility is a new major source of NOx emissions and is

subject to Appendix A for its NOx emissions. The proposed Facility is required to meet LAER

for NOx emissions and the Permittee must obtain NOx emission offsets at a ratio of 1.26 to 1.

Since VOC emissions from the proposed Facility are below the new major source threshold of

fifty (50) or more tons per year, the Permittee is not subject to regulation under Appendix A for

LAER and emission offsets pertaining to VOC emissions. However, the VOC emissions from the

proposed Facility are subject to, and must comply with, Best Available Control Technology

(BACT) pursuant to 310 CMR 7.02.

The Permittee has proposed a NOx emission limit for EU1 and EU2 of 2.0 parts per

million by volume, dry basis, corrected to 15 percent Oxygen (ppmvd @ 15% O2), one hour

block average. The Permittee provided a LAER analysis in the Application that included the

sources of data reviewed in support of this NOx LAER determination. These sources were EPA’s

RACT/BACT/LAER Clearinghouse, EPA’s Region IV National Combustion Turbine

Spreadsheet, the California Air Resources Board BACT Clearinghouse, the South Coast Air

Quality Management District BACT Clearinghouse, and New Jersey’s State of the Art Manual

for combustion turbines. The LAER analysis concluded that there are no large natural gas fired

combined cycle turbines where a NOx emission limit of less than 2.0 ppmvd @ 15% O2 has been

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 6 of 59

approved and subsequently demonstrated in practice. In addition, the two most recent NOx

LAER determinations for similar Massachusetts projects such as Brockton Power Company LLC

(Application No. 4B08015, Transmittal No. W207973 dated July 20, 2011) and Pioneer Valley

Energy Center LLC (Application No. 1-B-08-037, Transmittal No. X223780 dated December 31,

2010) were also 2.0 ppmvd @ 15% O2, one hour block average, during natural gas firing.

MassDEP has verified and concurred with the Permittee’s LAER analysis as presented in this

Application that this NOx emission limit constitutes NOx LAER for the proposed Facility.

The proposed Facility is a new major source of NOx emissions restricted to 144.8 tons

per year and the Permittee must obtain NOx emission offsets at a ratio of 1.26 to 1. The total

number of NOx emission offsets needed for the proposed Facility is (144.8) multiplied by (1.26),

or 183 tons per year. In accordance with 310 CMR 7.00: Appendix A(6), for a new major

stationary source of NOx located in an area that is not a nonattainment area, prior to commencing

operation of any emission unit(s), for which offsets are required under Appendix A, NOx

emission offsets must actually occur and be obtained from the same source or other sources

within the Ozone Transport Region.

The Permittee entered into an agreement on February 5, 2013 to purchase 59 tons per

year of rate-based NOx Emission Reduction Credits (ERCs) from The Newark Group Inc. These

ERCs were created and banked on April 7, 2010 by MassDEP, pursuant to the provisions of the

Commonwealth of Massachusetts Air Pollution Control Regulation at 310 CMR 7.00: Appendix

B, due to the shutdown of two (2) Massachusetts facilities owned and operated by The Newark

Group Inc. Thirty seven (37) tons per year of NOx ERCs were created and banked from the

shutdown of Natick Paperboard, 90 North Main Street, Natick and twenty two (22) tons per year

of NOx ERCs were created and banked from the shutdown of Haverhill Paperboard, 100 South

Kimball Street, Haverhill. ERCs in the Massachusetts Rate ERC Bank shall revert to the state to

be retired for the benefit of the environment if they have not been used by midnight of the date

ten years from the date of MassDEP approval, or April 7, 2020.

In addition, the Permittee entered into an agreement on April 4, 2013 to purchase 135

tons per year of rate-based NOx Emission Reduction Credits (ERCs) from Osram Sylvania Inc.

These ERCs were created and banked on March 11, 2004 by the Rhode Island Department of

Environmental Management, Office of Air Resources (OAR), pursuant to the provisions of the

State of Rhode Island Air Pollution Control Regulation No. 9, due to the shutdown of a number

of operations at Osram Sylvania Inc., 1193 Broad Street, Central Falls, Rhode Island. In

accordance with the Memorandum of Understanding by and between the State of Rhode Island

Department of Environmental Management and the Commonwealth of Massachusetts

Department of Environmental Protection on the Interstate Trading of NOx Emission Reduction

Credits (ERCs), dated April 2005, NOx ERCs generated in the State of Rhode Island may be

used in the Commonwealth of Massachusetts to meet emission offset requirements set forth in

310 CMR 7.00: Appendix A. The Osram Sylvania Inc. facility is located in the Ozone Transport

Region. Unlike Massachusetts ERCs in the Rate ERC Bank, Rhode Island ERCs are not subject

to retirement.

In total, the Permittee has entered into agreements to purchase 194 tons of rate-based

NOx ERCs. Since 183 tons per year of NOx emission offsets will be used to offset NOx emissions

from the Facility, 183 tons per year of NOx ERCs in the Rate ERC Bank must be retired at the

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 7 of 59

approved annual offset rate regardless of the Facility’s annual actual emissions. ERCs utilized as

offsets are considered “used” commencing with start-up of the Facility. If the Facility start-up

occurs after April 7, 2020, then the Permittee shall not use the abovementioned Newark Group

ERCs.

Appendix A requires the Permittee to demonstrate, and MassDEP to concur, that the

benefits of the proposed project significantly outweigh the environmental and social costs

imposed as a result of the project's location, construction or modification (310 CMR 7.00:

Appendix A (8)(b)). This demonstration requires analysis of alternative sites, sizes, production

processes, and environmental control techniques. The Application contains the details of the

required demonstration, a summary of which is provided here.

Alternative Site Evaluation

The Permittee’s site selection process focused on sites with shuttered or challenged coal

and/or oil fired electric generating facilities. The sites where these smaller, older oil and coal

fired electric generating facilities presently operate also typically offer ready access to

transmission, available water supply, and proximity to electric load. Developing a natural gas

fired facility at these challenged sites offers numerous and substantial benefits to the State and

local community. In addition to retention of jobs and tax revenues, when an older fossil fuel fired

electric generating facility is replaced by a state of the art natural gas fired electric generating

facility with sophisticated emissions controls, significant decreases in sulfur dioxide (SO2), CO2,

NOx, particulates, and emissions of other air pollutants are realized. Moreover, while site

contamination associated with an older coal or oil fired electric generating facility may go

unaddressed or, at least, may not get addressed in a timely manner when a facility is simply shut

down, the Permittee will address contamination and other environmental liability issues as an

integral part of the plans to construct and operate the proposed Facility.

The Salem site presents a significant number of attributes that satisfy the Permittee’s

location, environmental and community criteria set forth above. For example:

The existing Salem Harbor Station facility was considered to be one of the “Filthy Five”

electric generation plants in Massachusetts, with a long history of environmental

challenges. Indeed, construction of the proposed Facility on the landward portion of the

site will afford the Permittee the opportunity to clean up the portion of the site currently

occupied by the soon-to-be shutdown existing Salem Harbor Station facility, and return

that valuable waterfront land to productive use, consistent with State law. Having entered

commercial operation as an electric generating facility in 1951, the Salem Harbor site has

a long history as a site for electricity generation.

The existing Salem Harbor Station facility has been required by ISO - New England to

operate for reliability purposes through May 2014, offering the Permittee the opportunity

to minimize any gaps in electricity generation beyond that date through the development

and permitting of the new state of the art Facility.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 8 of 59

The site is nearby (less than two miles from) a natural gas pipeline facility, namely the

Maritimes and Northeast pipeline.

There is strong local support for the continuation of electric generation on the site as a

means of maximizing tax revenues and local employment. The Mayor, other city

officials, and state senators and representatives, have been supporters of continued

presence of electric generation at the site, in general, and particularly of the development

of this Facility.

There is support for potential reuse of the site as demonstrated by (1) the 2011 decision to

use Regional Greenhouse Gas Initiative (RGGI) funds to supplement the City of Salem’s

tax revenues for an eight-year period; (2) funding of the Salem Site Reuse Study by the

Massachusetts Clean Energy Center; and (3) the enactment of Chapter 209 of the Acts of

2012 and the establishment of the Salem Harbor Power Station Plan Revitalization Task

Force.

Permitting of the proposed Facility is expected given city and state support of the electric

power generation/site reuse concept, as well as compatibility of the proposed Facility

development with local zoning requirements.

The site is located in close proximity to the electric grid (National Grid system) and a

water supply.

The 65-acre site is sufficiently large to accommodate the proposed Facility and enable

further redevelopment opportunities.

The site offers the Permittee the opportunity to significantly reduce air, water supply,

wastewater, noise, visual, and other impacts relative to the existing Salem Harbor Station

facility.

The absence of new electric generation in the Northeastern Massachusetts/Boston

(NEMA/Boston) load zone. Indeed, it has been nearly a decade since any significant new

electric generation, i.e. Mystic 8 and 9, has been added in NEMA/Boston. Over the

course of these last ten years, there have been several unit retirements and still more

retirements are anticipated, while load in the NEMA/Boston area is not expected to

decrease.

The construction of the proposed Facility, along with demolition of the existing facility

and attendant remediation of the site, will bring a significant number of jobs over the

course of the next several years. The Permittee expects that approximately 30-40

permanent employees will be needed to operate the proposed Facility, assuring that

operations related employment at the Salem Harbor Station site will continue beyond the

June 1, 2014 retirement date of the existing facility.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 9 of 59

The demolition of the existing facility and remediation of the site will enable future use

of the remainder of the site for a variety of marine industrial purposes, thereby providing

opportunities to revitalize this valuable waterfront area.

In sum, the site satisfied the Permittee’s overall site selection objectives, as well as most,

if not all, of its location, environmental and community criteria. Accordingly, the site was

deemed to be superior to the alternative sites analyzed by the Permittee.

Alternative Project Sizes, Production Processes, and Environmental Control Techniques

Evaluation

The Permittee considered positioning the proposed Facility on the portion of the site

located outside of Chapter 91 jurisdiction. However, the Permittee concluded that the

approximately 14.5 acre, irregularly shaped, non-Chapter 91 portion of the site is not large

enough to accommodate the proposed Facility.

The Permittee also considered a wet-cooling system as a design alternative for the

proposed Facility. However, wet cooling was not considered to be a reasonable option because it

would result in greater impacts to Salem Harbor from withdrawal/discharge in terms of water

quality and impingement/entrainment versus the air cooled condenser option chosen.

The Permittee also considered a “dual fuel” alternative in which the proposed Facility

could run on either natural gas or diesel fuel oil. This alternative was considered not to be a

reasonable alternative due to intense local opposition to diesel fuel oil at the site and the potential

increased environmental risks (both to Salem Harbor and on and near the site) associated with

fuel delivery to/use on the site.

State and Regional Project Benefits

The Permittee has documented that electric generation that will be provided by the

proposed Facility is essential to ensure reliability in the NEMA/Boston load zone. The need for

reliability of the electric power grid clearly constitutes an overriding public benefit.

In addition, the public benefit served by the redevelopment of the site represented by the

proposed Facility has been expressly identified in recently enacted special legislation. Section 42

of Chapter 209 of the Acts of 2012 expressly provides:

“There shall be a plant revitalization task force established to implement a plan, adopt

rules and regulation and recommend necessary legislative action to ensure the full

deconstruction, remediation and redevelopment or repowering of the Salem Harbor

Station by December 31, 2016.”

The proposed Facility achieves all of the legislative goals of full demolition, remediation

and redevelopment of the site within the legislatively prescribed deadline of December 31, 2016.

It is difficult to conceive of any other project that could implement a plan for redevelopment of

the site by December 31, 2016.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 10 of 59

The proposed Facility also serves the Commonwealth’s interest in developing renewable

energy sources. That is, the quick-start technology designed into the proposed Facility facilitates

and supports the development of wind generation. Because wind power is an intermittent

resource, it is especially important for the region to be able to rely on clean and cost effective

quick-start electric generation during those periods when wind output is not available. While a

number of quick-start “peaking” facilities have recently been sited in New England, the proposed

state of the art quick-start technology at the proposed Facility will be more efficient and will

have fewer emissions than the peaking units which presently fill the gap when wind is

unavailable.

While the proposed Facility clearly fulfills the need for electricity reliability, the state of

the art natural gas fired emission units also offer significant air quality benefits. An analysis

prepared for the Permittee by Charles River Associates concludes that because the proposed

Facility “displaces other, less efficient generation on the New England Grid, operation of [the

Facility] reduces annual regional air emissions by approximately 457,626 tons (1.3%) of CO2,

984 tons (10%) of NOx, and 888 tons (8%) of SO2.1”

The important air quality improvements resulting from the proposed Facility are also

recognized in the Massachusetts Clean Energy and Climate Action Plan for 2020, which

estimates that the displacement of the former Salem Harbor Station and Somerset Station

facilities by natural gas fired power plants would result in a net 1.2 million metric ton reduction

in Greenhouse Gases (CO2e) in 2020.2

Local Project Benefits

Without the proposed Facility, the upcoming retirement of the Salem Harbor Station

facility would result in a significant loss of tax revenues for the City of Salem. In fiscal year

2010, former owner and operator of Salem Harbor Station, Dominion Energy Salem Harbor

LLC, paid $4.75 million in taxes, making the facility the largest contributor of tax revenue in the

City of Salem. The $4.75 million included a negotiated usage fee of $1.75 million, and property

taxes of $3 million, which included $800,000 attributable to the land. The proposed Facility will

help ensure that tax revenues associated with the site are maintained, thus not adversely affecting

the City’s budget and it will permit dollars from the RGGI Trust Account to be redirected away

from Salem and to other environmentally beneficial uses.

In addition, the proposed Facility will result in opportunities for public enjoyment of the

waterfront, consistent with the site’s location in a Designated Port Area. Currently, there is no

public access to the waterfront on the site. In contrast, as a result of the proposed Facility, the

public will have the opportunity to access paths on the Derby Street (residential) side of the site,

as well as linear access to view Salem Harbor. In addition, the demolition and remediation

efforts to be undertaken by the Permittee will enable future development options for the rest of

the site that could even further enhance public access to and enjoyment of the waterfront.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 11 of 59

Minimization of Environmental and Social Costs

The Permittee has committed to reduce and/or mitigate any environmental and social

impacts as a result of development of the site. The proposed Facility will minimize emissions

and will not cause or contribute to violation of any applicable air quality standard, through use of

only clean burning natural gas as fuel, advanced pollution control equipment, and highly

efficient combustion turbines. As a result, emissions from the proposed Facility will be amongst

the lowest of any fossil fuel fired electric generating facility in the United States.

MassDEP acknowledges that there will be environmental and social costs. There will be

new emissions to the ambient air which will be minimized through addition of control

technology and the purchase of NOx emission offsets. Further, the impacts to the ambient air

from the project are well within the standards and guidelines designed to protect public health.

Based upon review of the detailed demonstration provided by the Permittee in the

Application, MassDEP finds that the benefits of this project significantly outweigh this project's

environmental and social costs.

Notes:

1. “Analysis of the Impact of Salem Harbor Repowering on New England Air Emissions” dated November

21, 2012, p. 1, included in Appendix C to the Draft Environmental Impact Report, EEA# 14937; values updated per

June 10, 2013 letter to MassDEP, Attachment 4.

2. “Massachusetts Clean Energy and Climate Plan for 2020, A report to the Great and General Court pursuant

to the Global Warming Solutions Act (Chapter 298 of the Acts of 2008, and as codified at M.G.L. c. 21N)” dated

December 29, 2010, submitted by Secretary of Energy and Environmental Affairs Ian A. Bowles, p. 44.

3. AIR QUALITY IMPACT ANALYSIS

The EPA has developed National Ambient Air Quality Standards (NAAQS) for six air

contaminants known as criteria pollutants for the protection of public health and welfare. These

criteria pollutants are Nitrogen Dioxide (NO2), Sulfur Dioxide (SO2), Particulate Matter (PM),

Carbon Monoxide (CO), Ozone (O3), and Lead (Pb). The NAAQS include both primary and

secondary standards of different averaging periods, which protect public health and public

welfare, respectively.

One of the basic goals of federal and state air pollution control regulations is to ensure

that ambient air quality, including background, existing, and new sources, is in compliance with

the NAAQS. To identify new pollution sources with the potential to significantly alter ambient

air quality, the EPA and MassDEP have adopted significant impact levels (SILs) for the criteria

pollutants except O3 and Pb. New major sources (or major modifications of existing major

sources) are required to perform an air quality dispersion modeling analysis to predict air quality

impacts of the new (or modified) source in comparison to the SILs. If the predicted impact of the

new or modified source is less than the SIL for a particular pollutant and averaging period, then

the impact is considered “insignificant” for that pollutant and averaging period. However, if the

predicted impact of the new or modified source is equal to or greater than the SIL for a particular

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 12 of 59

pollutant and averaging period, then further impact evaluation is required. This additional

evaluation must include measured background levels of pollutants, and emissions from both the

proposed new (or modified) source and existing interactive sources (cumulative dispersion

modeling).

General Conditions

Dispersion modeling analyses were performed to assess the proposed Facility’s air impacts

of criteria air pollutants and air toxics against applicable SILs, NAAQS, and MassDEP’s Allowable

Ambient Levels (AALs) and Threshold Effects Exposure Limits (TELs) Guidelines for air toxics.

These analyses were conducted in accordance with EPA’s “Guideline on Air Quality Models”

(November 2005) and MassDEP’s “Modeling Guidance of Significant Stationary Sources of Air

Pollution” (June 2011) and as described in the Air Quality Modeling Protocol submitted to

MassDEP on August 29, 2012. The EPA-recommended AERMOD model (current AERMOD

version 12060, AERMAP version 11103) was used to perform the dispersion modeling. Dispersion

modeling was conducted in a manner that evaluated worst case operating conditions in an effort to

predict the highest impact for each pollutant and averaging period.

The dispersion modeling was conducted using five years (2006 through 2010) of surface

data collected by the National Weather Service (NWS) from the Logan Airport Station in

Boston, Massachusetts and the corresponding upper air data from Gray, Maine. These stations

are the closest NWS Stations and most representative of the Salem area. AERMET (version

11059), AERMINUTE (version 11059), and AERSURFACE were employed to prepare the

meteorological files. Land use within a 3 kilometer radius of the proposed Facility was

characterized as rural and water covered (approximately 64 percent). Therefore, rural dispersion

coefficients were used in the dispersion modeling. The modeling analyses included the two

combustion turbine units, auxiliary boiler, emergency generator and fire pump engines, and the

auxiliary cooling tower, all operating simultaneously. Three GE combustion turbine operating

loads (46, 75, and 100 percent loads), including a worst case combustion turbine start-up

condition, were modeled. Table 1 presents the maximum predicted ambient air quality impact

concentrations for the proposed Facility. The proposed Facility was predicted to have maximum

ambient air quality impact concentrations below SILs for all pollutants and averaging periods,

except for 1-Hour NO2 and 24-Hour PM2.5.

Table 1

Criteria

Pollutant

Averaging

Period

Primary

NAAQS

(ug/m3)

Secondary

NAAQS

(ug/m3)

Significant

Impact Level

(ug/m3)

Maximum

Predicted Facility

Impact (ug/m3)

NO2 Annual (1)

1-Hour (2)

100

188

Same

None

1

7.5

0.4

41.8

SO2 Annual (1,3)

24-Hour (3,4)

3-Hour (4)

1-Hour (5,6)

80

365

None

196

None

None

1,300

None

1

5

25

7.8

0.03

0.7

1.1

1.0

PM2.5 Annual (7)

24-Hour (8)

12

35

Same

Same

0.3

1.2

0.12

3.2

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 13 of 59

Table 1

Criteria

Pollutant

Averaging

Period

Primary

NAAQS

(ug/m3)

Secondary

NAAQS

(ug/m3)

Significant

Impact Level

(ug/m3)

Maximum

Predicted Facility

Impact (ug/m3)

PM10 24-Hour (9)

150 Same 5 4.3

CO 8-Hour (4)

1-Hour (4)

10,000

40,000

None

None

500

2,000

112.4

313.6

O3 8-Hour (10)

147 Same NA NA

Pb 3-Month (1)

0.15 Same NA < 0.00016

Table 1 Notes:

1. Not to be exceeded.

2. Compliance based on 3 year average of the 98th

percentile of the daily maximum 1 hour average at each

monitor within an area.

3. EPA has indicated that the 24 hour and annual average primary standards for SO2 will be revoked.

4. Not to be exceeded more than once per year.

5. Compliance based on 3 year average of 99th

percentile of the daily maximum 1 hour average at each

monitor within an area.

6. The 1 hour SO2 standard was effective as of August 23, 2010.

7. Compliance based on 3 year average of weighted annual mean PM2.5 concentrations at community oriented

monitors.

8. Compliance based on 3 year average of 98th

percentile of 24 hour concentrations at each population

oriented monitor within an area.

9. Not to be exceeded more than once per year on average over 3 years.

10. Compliance based on 3 year average of fourth highest daily maximum 8 hour average ozone concentrations

measured at each monitor within an area.

Table 1 Key:

NAAQS = National Ambient Air Quality Standards

EPA = United States Environmental Protection Agency

NO2 = Nitrogen Dioxide

SO2 = Sulfur Dioxide

PM2.5 = Particulate Matter less than or equal to 2.5 microns in diameter

PM10 = Particulate Matter less than or equal to 10 microns in diameter

CO = Carbon Monoxide

O3 = Ozone

Pb = Lead

ug/m3 = micrograms per cubic meter

NA = Not Applicable

< = less than

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 14 of 59

Cumulative Dispersion Modeling

Since dispersion modeling predicted maximum impact concentrations above SILs for 1

Hour NO2 and 24-Hour PM2.5, cumulative impact modeling was performed for these pollutants

with the same pollutant emissions from existing interactive sources and measured background

levels to compare against the NAAQS for 1-Hour NO2 and 24-Hour PM2.5. Background

concentrations were obtained from MassDEP’s Lynn monitoring location, approximately 5.9

miles southwest of the Facility. The existing interactive sources in Massachusetts nearby the

Facility considered in the cumulative modeling were: a) General Electric Lynn and Wheelabrator

Saugus for 1-Hour NO2 and 24-Hour PM2.5; and b) Rousselot Peabody, Peabody Municipal

Light, and Marblehead Municipal Light for 1-Hour NO2. Table 2 shows the cumulative impacts.

The results of the cumulative impact analysis show that under no condition did the proposed

Facility’s worst case emissions in combination with emissions from the existing interactive

sources plus measured background levels result in concentrations which exceeded the applicable

NAAQS.

Table 2

Criteria

Pollutant

Averaging

Period

Cumulative Impact,

Facility Plus Existing

Sources (2)

(ug/m3)

Background

(ug/m3) (1)

Total Impact Plus

Background

(ug/m3)

Primary

NAAQS

(ug/m3)

NO2 1-Hour 83.7 (3)

82.3 166.0 188

PM2.5 24-Hour 3.5 18.9 22.4 35

Table 2 Notes:

1. Background concentrations are based on the measured values from 2010 through 2012. Short term

background concentrations for 24-Hour PM2.5 and 1-Hour NO2, are the average of the 98th

percentile values over the

3 years (2010-2012). These assumptions are consistent with the form of the NAAQS for the pollutant.

2. Consistent with EPA modeling guidance for NAAQS compliance assessments, impact concentrations are

based on the 5 year average of the 1st highest values occurring in each year for the 24-Hour PM2.5 concentration, and

the 5 year average of the 8th

highest daily maximum concentrations occurring in each year for the 1-Hour NO2

concentration.

3. The modeled cumulative impacts represent an EPA-approved Tier 2 approach reflecting an 80 percent

conversion of NOx emissions to NO2 in the ambient air.

Table 2 Key:

NAAQS = National Ambient Air Quality Standards

NO2 = Nitrogen Dioxide

PM2.5 = Particulate Matter less than or equal to 2.5 microns in diameter

ug/m3 = micrograms per cubic meter

Air Toxics Analysis

MassDEP has established health based ambient air guidelines for a variety of chemicals

(air toxics). These air guidelines establish two limits for each chemical listed: an AAL, which is

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 15 of 59

based on an annual average concentration; and a TEL, which is based on a 24-hour time period.

In general, AALs are lower than TELs, and represent the concentration associated with a one in

one million excess lifetime cancer risk, assuming a lifetime of continuous exposure to that

concentration. For chemicals that do not pose cancer risks, the AAL is equal to the TEL.

Table 3 presents the projected maximum impacts for each air toxic that will potentially be

emitted by the proposed Facility for which an AAL or TEL has been established. Impacts are

based on the worst case emission scenarios predicted by AERMOD. As shown in Table 3, the

proposed Facility’s maximum predicted ambient air quality impact concentrations were

significantly below applicable AALs and TELs for all of the air toxics modeled.

Table 3

Pollutant Averaging Period AAL/TEL (ug/m3) Maximum Predicted Facility

Impact (ug/m3)

Acetaldehyde 24-Hour (TEL)

Annual (AAL)

2

0.5

0.053708

0.000775

Ammonia 24-Hour (TEL)

Annual (AAL)

100

100

1.093673

0.034497

Benzene 24-Hour (TEL)

Annual (AAL)

1.74

0.12

0.080104

0.000591

1,3-Butadiene 24-Hour (TEL)

Annual (AAL)

1.20

0.003

0.002035

0.000019

o-Dichlorobenzene 24-Hour (TEL)

Annual (AAL)

81.74

81.74

0.000047

0.000006

p-Dichlorobenzene 24-Hour (TEL)

Annual (AAL)

122.61

0.18

0.000047

0.000006

Ethylbenzene 24-Hour (TEL)

Annual (AAL)

300

300

0.012962

0.000409

Formaldehyde 24-Hour (TEL)

Annual (AAL)

2.0

0.8

0.203990

0.005265

Naphthalene 24-Hour (TEL)

Annual (AAL)

14.25

14.25

0.009739

0.000067

Propylene Oxide 24-Hour (TEL)

Annual (AAL)

6

0.3

0.334015

0.002126

Sulfuric Acid 24-Hour (TEL)

Annual (AAL)

2.72

2.72

0.053184

0.001841

Toluene 24-Hour (TEL)

Annual (AAL)

80

20

0.083392

0.001857

Xylenes 24-Hour (TEL)

Annual (AAL)

11.80

11.80

0.047138

0.000942

Arsenic 24-Hour (TEL)

Annual (AAL)

0.003

0.0003

0.000012

0.000001

Beryllium 24-Hour (TEL)

Annual (AAL)

0.001

0.0004

0.000000

0.0000001

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 16 of 59

Table 3

Pollutant Averaging Period AAL/TEL (ug/m3) Maximum Predicted Facility

Impact (ug/m3)

Cadmium 24-Hour (TEL)

Annual (AAL)

0.003

0.001

0.000044

0.000006

Chromium (total) 24-Hour (TEL)

Annual (AAL)

1.36

0.68

0.001137

0.000013

Chromium (hexavalent) 24-Hour (TEL)

Annual (AAL)

0.003

0.0001

0.000205

0.000002

Copper 24-Hour (TEL)

Annual (AAL)

0.54

0.54

0.00003

0.00000

Lead (1)

24-Hour (TEL)

Annual (AAL)

0.14

0.07

0.00009

0.000003

Mercury (elemental) 24-Hour (TEL)

Annual (AAL)

0.14

0.07

0.00001

0.000001

Nickel 24-Hour (TEL)

Annual (AAL)

0.27

0.18

0.00021

0.00001

Selenium 24-Hour (TEL)

Annual (AAL)

0.54

0.54

0.00002

0.0000002

Vanadium 24-Hour (TEL)

Annual (AAL)

0.27

0.27

0.00009

0.00001

Table 3 Notes:

1. Most air toxics do not have a NAAQS, with the exception of lead.

Table 3 Key:

AAL = Allowable Ambient Limit

TEL = Threshold Effects Exposure Limit

ug/m3 = micrograms per cubic meter

Preconstruction Monitoring Analysis

As described in the “Cumulative Dispersion Modeling” section above, ambient

background monitoring data from MassDEP’s Lynn monitoring site for the three (3) year period

of 2010 through 2012 were used to characterize criteria pollutant ambient air impacts. PSD

regulations allow proposed sources to use existing monitoring data in lieu of PSD

preconstruction monitoring requirements for a pollutant if the source can demonstrate that its

ambient air impact is less than a de minimis amount (also called a significant monitoring

concentration or SMC) as specified in those regulations. As shown in Table 4 below, dispersion

modeling conducted by the Permittee predicted maximum proposed Facility impact

concentrations well below corresponding SMC levels for all pollutants for which SMCs exist.

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Footprint Power Salem Harbor Development LP

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Transmittal No. X254064

Application No. NE-12-022

Page 17 of 59

Table 4

Pollutant Averaging Period SMC (ug/m3) Maximum Predicted Facility

Impact (ug/m3)

NO2 Annual 14 0.4

SO2 24-Hour 13 0.7

PM10 24-Hour 10 4.3

CO 8-Hour 575 112.4

Table 4 Key:

SMC = Significant Monitoring Concentration

ug/m3 = micrograms per cubic meter

EPA had also established an SMC for PM2.5 but this SMC was remanded by the United

States Court of Appeals for the DC Circuit on January 22, 2013 (No. 10-1413, Sierra Club v.

EPA). On March 4, 2013, the EPA Office of Air Quality Planning and Standards issued guidance

to applicants and regulators with regard to the ramifications of the January 22, 2013 Appeals

Court decision. The pertinent excerpt of this recent EPA guidance is as follows:

“As a result of the Court’s decision, Federal PSD Permits issued henceforth by either the

EPA or a delegated state permitting authority pursuant to 40 CFR 52.21 should not rely

on the PM2.5 SMC to allow applicants to avoid compiling air quality monitoring data for

PM2.5. Accordingly, all applicants requesting a federal PSD permit, including those

having already applied for but have not yet received the permit, should submit ambient

PM2.5 monitoring data in accordance with the Clean Air Act requirements whenever

either direct PM2.5 or any PM2.5 precursor is emitted in a significant amount. In lieu of

applicants setting out PM2.5 monitors to collect ambient data, applicants may submit

PM2.5 ambient data collected from existing monitoring networks when the permitting

Authority deems such data to be representative of the air quality in the area of concern for

the year preceding receipt of the application. We believe that applicants will generally be

able to rely on existing representative monitoring data to satisfy the monitoring data

requirement.”

The Lynn monitoring site, located approximately 5.9 miles to the southwest of the

proposed Facility, is representative of the proposed Facility site due to its proximity. Use of the

data from this monitoring site is conservative for the following reasons:

a) Lynn is a more industrialized and densely populated area than the proposed Facility

site, particularly without the influence of the existing Salem Harbor Station after its

shutdown prior to when the proposed Facility commences operation. The proposed

Facility site is located adjacent to Salem Harbor, a significantly large water body where

potential emission sources are more limited. The Lynn monitoring site is located closer to

the metropolitan Boston area than the proposed Facility site. Any potentially elevated

ambient background pollutant concentrations from mobile and stationary emission

sources located in and around the Boston metropolitan area that may be transported to the

proposed Facility site via predominant winds from the south or southwest, typically pass

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Footprint Power Salem Harbor Development LP

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Transmittal No. X254064

Application No. NE-12-022

Page 18 of 59

the Lynn monitoring location and are therefore represented in the measurement data

collected at the Lynn monitoring site.

b) The General Electric Lynn and Wheelabrator Saugus facilities, which have been

identified by MassDEP as the only two major industrial emission sources to be modeled

cumulatively with the proposed Facility emissions for 24-Hour PM2.5, are located slightly

less than 2 miles from the Lynn monitoring site but are located about 7 miles from the

proposed Facility site. Therefore, the cumulative modeling compliance demonstration,

which includes both the background ambient concentrations and impacts from the

interactive existing major sources likely double counts the contribution of these sources

and therefore, provides additional conservatism to the required modeling results by

potentially overestimating cumulative impact concentrations. This is particularly

significant given that these two major sources are located to the south-southwest of the

monitoring site, which means that they could potentially influence the monitoring site

concentrations during winds coming from the south or southwest, the predominant wind

directions in this area.

For the reasons set forth above, in accordance with the PSD regulations and recent EPA

guidance, MassDEP has determined that preconstruction monitoring is not required.

Justification for Using Significant Impact Levels (SILs) for PM2.5

Despite the fact that the PSD regulations dealing with SILs for PM2.5 were partially

vacated and remanded (at EPA’s request) in the January 22, 2013 Appeals Court decision, the

use of the PM2.5 SILs is still valid in certain circumstances in which ambient background

concentrations are relatively low. EPA did not concede that it lacked authority to promulgate

SILs and the court found that it was not necessary to address the question of whether EPA had

such authority. In fact, the SILs were vacated and remanded in only PSD sections 40 CFR

51.166(k)(2) and 52.21(k)(2) but were not vacated in 40 CFR 51.165(b)(2). This is most likely

because the text of this latter regulation does not exempt a source from ambient air quality

analysis but states that if a source located in an attainment area exceeds a SIL in a nonattainment

area (or predicted nonattainment situation), it is deemed to have contributed to or caused a

violation of a NAAQS.

Key examples in the Appeals Court decision supporting the vacature and remand

involved cases in which the ambient air quality background is very close to the NAAQS. This is

not the case in the Salem region where the PM2.5 background is only slightly over half of the

NAAQS, 18.9 ug/m3 vs. 35 ug/m

3. Therefore, use of the prior PM2.5 SILs is appropriate in the

case of the ambient air quality impact analysis for the proposed Facility because the background

concentrations plus the SILs still leave a significant margin before the NAAQS would come

close to being jeopardized.

Use of the prior PM2.5 SILs is also consistent with the recent EPA guidance on this matter

which states 1:

The EPA does not interpret the Court’s decision to preclude the use of SILs for PM2.5

entirely but additional care should be taken by permitting authorities in how they apply

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Footprint Power Salem Harbor Development LP

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Transmittal No. X254064

Application No. NE-12-022

Page 19 of 59

those SILs so that the permitting record supports a conclusion that the source will not

cause or contribute to a violation of the PM2.5 NAAQS.

PSD permitting authorities have the discretion to select PM2.5 SIL values if the

permitting record provides sufficient justification for the SIL values that are used and the

manner in which they are used to support a permitting decision.

The PM2.5 SIL values in the EPA’s regulations may continue to be used in some

circumstances if permitting authorities take care to consider background concentrations

prior to using these SIL values in particular ways.

Because of the Court’s decision vacating the PM2.5 SMC, all applicants for a federal

PSD permit should include ambient PM2.5 monitoring data as part of the air quality

impacts analysis. If the preconstruction monitoring data shows that the difference

between the PM2.5 NAAQS and the monitored PM2.5 background concentrations in the

area is greater than the EPA’s PM2.5 SIL value, then the EPA believes it would be

sufficient in most cases for permitting authorities to conclude that a proposed source with

a PM2.5 impact below the PM2.5 SIL value will not cause or contribute to a violation of

the PM2.5 NAAQS and to, therefore, forego a more comprehensive cumulative modeling

analysis for PM2.5.

As part of a cumulative analysis, the applicant may continue to show that the proposed

source does not contribute to an existing violation of the PM2.5 NAAQS by

demonstrating that the proposed source’s PM2.5 impact does not significantly contribute

to an existing violation of the PM2.5 NAAQS. However, permitting authorities should

consult with the EPA before using any of the SIL values in the EPA’s regulations for this

purpose (including the PM2.5 SIL value in section 51.165(b)(2), which was not vacated

by the Court).

Notes:

1. EPA, Office of Air Quality Planning and Standards, “Circuit Court Decision on PM2.5 Significant Impact

Levels and Significant Monitoring Concentration – Questions and Answers”, March 4, 2013.

http://www.epa.gov/nsr/documents/20130304qa.pdf

4. ACCIDENTAL RELEASE MODELING OF AQUEOUS AMMONIA (NH3)

Aqueous NH3 will be used as the reducing agent in the proposed Facility’s SCR system

to control NOx emissions. A solution of aqueous NH3 (19% solution) will be stored onsite in an

above-ground 34,000-gallon single-walled steel tank located north of the building structures. The

tank, as well as NH3 transfer pumps, valves, and piping will be contained within a concrete dike

designed to contain 110 percent of the total volume of the tank.

In order to minimize the exposed surface area of any aqueous NH3 that enters the

containment area, passive evaporative controls (polyethylene balls or equivalent) will be utilized

to reduce the surface area by 90 percent. In order to further mitigate the potential impacts of an

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Footprint Power Salem Harbor Development LP

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accidental NH3 release, the entire tank and containment area will be located within an enclosure

with walls that will be fully sealed and ventilation provided by roof vents.

The aqueous NH3 storage tank will be constructed in accordance with the Massachusetts

Department of Public Safety requirements for storage tanks greater than 10,000 gallons

containing material other than water. The dike wall and enclosure surrounding the tank will

decrease the risk of damage to the tank caused by accidental vehicle contact.

Transfer from NH3 delivery trucks to the storage tank will take place within a contained

concrete storage unloading pad with drainage design such that any spills during NH3 delivery

will drain into the containment area. Delivery trucks will be required to have fast-acting shutoff

valves in the unlikely event that a leak or other problem should arise. A hose from the top of the

tank connected back to the truck will return displaced vapor to the truck, or an equivalent method

for control of transfer losses will be used.

The storage tank will be equipped with level monitoring instrumentation that will be

continuously monitored in the proposed Facility’s control room. In the event that the tank level

approaches an overfill condition during filling, a high level alarm will sound, initiating an

immediate response to the situation. In addition, NH3 sensors in the enclosure will alert plant

staff and prevent the accumulation of significant amounts of NH3 in the containment area.

Ammonia in aqueous solution is volatile, and the accidental release of this material would

result in some release of NH3 to the ambient air. Therefore, a worst case accidental release

scenario was performed to evaluate the potential health impacts of such a release. This scenario

assumed a release of the entire contents of the tank into the containment area, and conservatively

evaluated the air quality impacts of such a release at the nearest projected controlled access

perimeter (PCAP), approximately 230 feet from the NH3 storage area. The NH3 emissions

resulting from this hypothetical worst case release scenario were calculated using the Area

Locations of Hazardous Atmospheres model. This model was developed by EPA and the

National Oceanic and Atmospheric Administration, and is included as a prescribed technique

under the EPA Risk Management Program (RMP) guidance.

In order to conservatively evaluate offsite consequences of an NH3 release, the

AERMOD dispersion model used for evaluation of air quality impacts from the exhaust stacks

was used to determine maximum NH3 concentrations at receptors at or near the PCAP, evaluated

in terms of the American Industrial Hygiene Association (AIHA) Emergency Response Planning

Guideline Level 1 (ERPG-1) of 25 parts per million (ppm) by volume, and the ERPG-2 of 150

ppm by volume. ERPG-1 is defined as the maximum airborne concentration below which nearly

all individuals could be exposed to for up to one hour without experiencing either mild transient

health effects and/or a clearly defined objectionable odor. ERPG-2 is defined as the maximum

airborne concentration which it is believed that nearly all individuals could be exposed to for up

to one hour without experiencing or developing irreversible or other serious health effects or

symptoms that could impair the ability to take self directed protective action.

The results of the AERMOD model indicate that in the event of a hypothetical worst case

release, the NH3 concentrations would be less than the ERPG-1 level of 25 ppm by volume at all

locations outside of the PCAP. Thus, the NH3 concentrations at all locations outside of the PCAP

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Footprint Power Salem Harbor Development LP

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would be well below the ERPG-2 level of 150 ppm by volume. Table 5 presents the results of the

predicted 1 hour maximum concentrations of NH3:

Table 5

Location Distance from NH3

Storage Enclosure (Feet)

ERPG-1 ERPG-2 NH3 Concentration

(Maximum Hourly Value,

ppm)

Power Plant North

PCAP

230 25 150 20.2

Power Plant West

PCAP

340 25 150 13.1

Power Plant East

PCAP

450 25 150 4.4

Nearest Residence

(Fort Avenue)

570 25 150 6.7

Salem Essex

Sewerage District

(SESD)

750 25 150 6.8

Table 5 Key:

PCAP = Projected Controlled Access Perimeter

ERPG-1 = Emergency Response Planning Guideline Level 1

ERPG-2 = Emergency Response Planning Guideline Level 2

NH3 = Ammonia

ppm = parts per million by volume

In addition, Section 112(r) of the Clean Air Act and associated EPA regulations at 40

CFR Part 68 apply to owners or operators of stationary sources producing, processing, handling

or storing toxic or flammable substances. The substances regulated under Section 112(r) and

their threshold quantities are listed at Section 68.130 of 40 CFR Part 68. Although the proposed

Facility will not store regulated substances above the threshold quantities, the general duty clause

in Section 112(r)(1) applies:

“The owners and operators of stationary sources producing, processing, handling or

storing hazardous substances have a general duty in the same manner and to the same extent as

Section 654, Title 29 of the United States Code, to identify hazards which may result from

accidental releases using appropriate hazard assessment techniques, to design and maintain a safe

facility taking such steps as are necessary to prevent releases, and minimize the consequences of

accidental releases which do occur.”

The Permittee shall take all steps necessary to meet the general duty clause above.

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4. EMISSION UNIT (EU) IDENTIFICATION

Each Emission Unit (EU) identified in Table 6 is subject to and regulated by this Plan

Approval:

Table 6

EU# Description Design Capacity Pollution Control

Device (PCD)

EU1 General Electric Model No. 107F Series 5

Combustion Turbine/Heat Recovery Steam Generator

Including Duct Burner

2,449 MMBtu/hr,

HHV (energy

input)

346 MW (electric

power output)

Dry Low NOx

Combustors (PCD1)

Selective Catalytic

Reduction (PCD2)

CO Oxidation Catalyst

(PCD3)

EU2 General Electric Model No. 107F Series 5

Combustion Turbine/Heat Recovery Steam Generator

Including Duct Burner

2,449 MMBtu/hr,

HHV (energy

input)

346 MW (electric

power output)

Dry Low NOx

Combustors (PCD4)

Selective Catalytic

Reduction (PCD5)

CO Oxidation Catalyst

(PCD6)

EU3 Cleaver Brooks Model No. CBND-80E-300D-65 or

equivalent

Auxiliary Boiler

80 MMBtu/hr,

HHV (energy

input)

Ultra Low NOx Burners

(PCD7)

EU4 Cummins Model No. DQFAA or equivalent

Emergency Engine/Generator

7.4 MMBtu/hr,

HHV (energy

input)

1102 bhp (engine

mechanical power

output)

750 KW

(generator electric

power output)

None

EU5 Cummins Model No. CFP9E-F50 or equivalent

Fire Pump Engine

2.7 MMBtu/hr,

HHV (energy

input)

371 bhp (engine

mechanical power

output)

None

Table 6 Key:

EU# = Emission Unit Number

No. = Number

MMBtu/hr = fuel heat input, million British thermal units per hour

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HHV = higher heating value basis

bhp = mechanical engine rating, brake horsepower

MW = generator net electrical output, Megawatts

KW = generator net electrical output, Kilowatts

NOx = Oxides of Nitrogen

CO = Carbon Monoxide

5. APPLICABLE REQUIREMENTS

A. OPERATIONAL, PRODUCTION and EMISSION LIMITS

The proposed Facility is subject to, and the Permittee shall ensure that the proposed

Facility shall not exceed the Operational, Production, and Emission Limits as contained in Table

7 below, including footnotes:

Table 7

EU# Operational / Production

Limit

Air Contaminant Emission Limit

EU1, EU2 Operation at > MECL, (17)

excluding start-ups and

shutdowns

Fuel Heat Input Rate of

each EU:

< 2,449 MMBtu per hour,

HHV

Natural Gas shall be the

only fuel of use.

Fuel Heat Input of each EU:

< 18,888,480 MMBtu,

HHV per 12-month rolling

period (9)

NOx (no duct firing) < 18.1 lb/hr (1, 2)

< 0.0074 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2 (1)

< 0.051 lb/MW-hr (1, 2, 10, 14)

< 15.0 ppmvd @ 15% O2

or

< 0.43 lb/MW-hr (13)

NOx (duct firing) < 18.1 lb/hr (1, 2)

< 0.0074 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2 (1)

< 0.055 lb/MW-hr (1, 2, 15)

< 15.0 ppmvd @ 15% O2

or

< 0.43 lb/MW-hr (13)

CO (no duct firing) < 11.0 lb/hr (1, 2)

< 0.0045 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2 (1)

< 0.031 lb/MW-hr (1, 2, 10, 14)

CO (duct firing) < 11.0 lb/hr (1, 2)

< 0.0045 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2 (1)

< 0.033 lb/MW-hr (1, 2, 15)

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Footprint Power Salem Harbor Development LP

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Table 7

EU# Operational / Production

Limit

Air Contaminant Emission Limit

EU1, EU2 Operation at > MECL, (17)

excluding start-ups and

shutdowns

Fuel Heat Input Rate of

each EU:

< 2,449 MMBtu per hour,

HHV

Natural Gas shall be the

only fuel of use.

Fuel Heat Input of each EU:

< 18,888,480 MMBtu,

HHV per 12-month rolling

period (9)

VOC (no duct firing),

as Methane (CH4)

< 3.0 lb/hr (1, 2)

< 0.0013 lb/MMBtu (1)

< 1.0 ppmvd @ 15% O2 (1)

< 0.009 lb/MW-hr (1, 2, 10, 14)

VOC (duct firing),

as Methane (CH4)

< 5.4 lb/hr (1, 2)

< 0.0022 lb/MMBtu (1)

< 1.7 ppmvd @ 15% O2 (1)

< 0.016 lb/MW-hr (1, 2, 15)

S in Fuel < 0.5 grains/100 scf

SO2 (no duct firing) < 3.7 lb/hr (1, 2)

< 0.0015 lb/MMBtu (1)

< 0.3 ppmvd @ 15% O2 (1)

< 0.010 lb/MW-hr (1, 2, 10, 14)

SO2 (duct firing) < 3.7 lb/hr (1, 2)

< 0.0015 lb/MMBtu (1)

< 0.3 ppmvd @ 15% O2 (1)

< 0.011 lb/MW-hr (1, 2, 15)

H2SO4 (no duct firing) < 2.3 lb/hr (1, 2)

< 0.0010 lb/MMBtu (1)

< 0.1 ppmvd @ 15% O2 (1)

< 0. 007 lb/MW-hr (1, 2, 10, 14)

H2SO4 (duct firing) < 2.3 lb/hr (1, 2)

< 0.0010 lb/MMBtu (1)

< 0.1 ppmvd @ 15% O2 (1)

< 0.008 lb/MW-hr (1, 2, 15)

PM/PM10/PM2.5 (no duct

firing)

< 15.5 lb/hr (1, 2, 8)

< 0.0088 lb/MMBtu (1, 8)

< 0.044 lb/MW-hr (1, 2, 8, 10, 14)

PM/PM10/PM2.5 (duct firing) < 15.5 lb/hr (1, 2, 8)

< 0.0067 lb/MMBtu (1, 8)

< 0.049 lb/MW-hr (1, 2, 8, 15)

NH3 (no duct firing) < 6.6 lb/hr (1, 2)

< 0.0027 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2 (1)

< 0.019 lb/MW-hr (1, 2, 10, 14)

NH3 (duct firing) < 6.6 lb/hr (1, 2)

< 0.0027 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2 (1)

< 0.020 lb/MW-hr (1, 2, 15)

Greenhouse Gases, CO2e < 825 lb/MW-hr (11)

< 895 lb/MW-hr (16)

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Table 7

EU# Operational / Production

Limit

Air Contaminant Emission Limit

EU1, EU2 Operation at > MECL, (17)

excluding start-ups and

shutdowns

Fuel Heat Input Rate of

each EU:

< 2,449 MMBtu per hour,

HHV

Natural Gas shall be the

only fuel of use.

Fuel Heat Input of each EU:

< 18,888,480 MMBtu,

HHV per 12-month rolling

period (9)

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour (5)

Operation at < MECL

during start-ups (3, 12)

Start-up duration:

< 45 minutes (3, 12)

Natural Gas shall be the

only fuel of use.

NOx < 89 lb per event (4, 12)

CO < 285 lb per event (4, 12)

VOC,

as Methane (CH4)

< 23 lb per event (4, 12)

S in Fuel < 0.5 grains/100 scf

SO2 < 2.0 lb per event (4, 12)

H2SO4 < 1.3 lb per event (4, 12)

PM/PM10/PM2.5 < 7.3 lb per event (4, 8, 12)

NH3 NA

Opacity < 10% (5, 12)

Operation at < MECL

during shutdowns (3, 12)

Shutdown duration:

< 27 minutes (3, 12)

Natural Gas shall be the

only fuel of use.

NOx < 10 lb per event (12)

CO < 151 lb per event (12)

VOC,

as Methane (CH4)

< 29 lb per event (12)

S in Fuel < 0.5 grains/100 scf

SO2 < 0.3 lb per event (12)

H2SO4 < 0.2 lb per event (12)

PM/PM10/PM2.5 < 5.8 lb per event (8, 12)

NH3 NA

Opacity

< 10% (5, 12)

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Table 7

EU# Operational / Production

Limit

Air Contaminant Emission Limit

EU3 Operation at > MECL (18)

Fuel Heat Input Rate:

< 80 MMBtu per hour,

HHV

Natural Gas shall be the

only fuel of use.

Total Fuel Heat Input:

< 525,600 MMBtu, HHV

per 12-month rolling period (9)

NOx < 0.88 lb/hr (1)

< 0.011 lb/MMBtu (1)

< 9.0 ppmvd @ 3% O2 (1)

CO < 2.8 lb/hr (1)

< 0.035 lb/MMBtu (1)

< 47 ppmvd @ 3% O2 (1)

VOC,

as Methane (CH4)

< 0.4 lb/hr (1)

< 0.005 lb/MMBtu (1)

< 11.8 ppmvd @ 3% O2 (1)

S in Fuel < 0.5 grains/100 scf

SO2 < 0.12 lb/hr (1)

< 0.0015 lb/MMBtu (1)

< 0.9 ppmvd @ 3% O2 (1)

H2SO4 < 0.009 lb/hr (1)

< 0.0001 lb/MMBtu (1)

< 0.05 ppmvd @ 3% O2 (1)

PM/PM10/PM2.5 < 0.4 lb/hr (1, 8)

< 0.005 lb/MMBtu (1, 8)

Greenhouse Gases, CO2e < 119.0 lb/MMBtu

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour (5)

EU4 < 300 hours of operation

per 12-month rolling period

Ultra Low Sulfur Diesel

Fuel Oil shall be the only

fuel of use.

NOx and VOC (NMHC as

CH1.8),

Combined Total

< 11.60 lb/hr (6)

< 4.8 gm/bhp-hr (6)

< 6.4 gm/KW-hr (6)

CO < 6.34 lb/hr (6)

< 2.6 gm/bhp-hr (6)

< 3.5 gm/KW-hr (6)

S in Fuel < 0.0015% by weight

SO2 < 0.011 lb/hr (6)

H2SO4 < 0.0009 lb/hr (6)

PM/PM10/PM2.5 < 0.36 lb/hr (6)

< 0.15 gm/bhp-hr (6)

< 0.2 gm/KW-hr (6)

Greenhouse Gases, CO2e < 162.85 lb/MMBtu

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour

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Table 7

EU# Operational / Production

Limit

Air Contaminant Emission Limit

EU5 < 300 hours of operation

per 12-month rolling period

Ultra Low Sulfur Diesel

Fuel Oil shall be the only

fuel of use.

NOx and VOC (NMHC as

CH1.8),

Combined Total

< 2.44 lb/hr (6)

< 3.0 gm/bhp-hr (6)

< 4.0 gm/KW-hr (6)

CO < 2.14 lb/hr (6)

< 2.6 gm/bhp-hr (6)

< 3.5 gm/KW-hr (6)

S in Fuel < 0.0015% by weight

< 300 hours of operation

per 12-month rolling period

Ultra Low Sulfur Diesel

Fuel Oil shall be the only

fuel of use.

SO2 < 0.004 lb/hr (6)

H2SO4 < 0.0003 lb/hr (6)

PM/PM10/PM2.5 < 0.12 lb/hr (6)

< 0.15 gm/bhp-hr (6)

< 0.2 gm/KW-hr (6)

Greenhouse Gases, CO2e < 162.85 lb/MMBtu

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour

EU1, EU2,

EU3, EU4,

EU5

NA Smoke 310 CMR 7.06 (1)(a)

Facility-Wide NA NOx < 144.8 TPY (7)

CO < 106.4 TPY (7)

VOC < 28.0 TPY (7)

SO2 < 28.8 TPY (7)

PM/PM10/PM2.5 < 109.4 TPY (7, 8)

NH3 < 51.0 TPY (7)

H2SO4 < 18.8 TPY (7)

Pb < 0.00013 TPY (7)

Formaldehyde or Single HAP < 6.6 TPY (7)

Total HAPs < 13.1 TPY (7)

CO2 < 2,277,333 TPY (7)

Greenhouse Gases, CO2e < 2,279,530 TPY (7)

Table 7 Notes:

1. Emission limits are one hour block averages and do not apply during start-ups and shutdowns.

2. Emission rates are based on burning natural gas in any one combustion turbine at a maximum natural gas

firing rate of 2,449 MMBtu/hr, HHV, at 90 ºF ambient temperature, 14.7 psia ambient pressure, and 60% ambient

relative humidity (combustion turbine and duct burner combined). These constitute worst case emissions.

3. Start-ups include the time from flame-on in the combustor (after a period of downtime) until the minimum

emissions compliance load (MECL) is reached. Shutdowns include the time from dropping below the MECL until

flame-out.

4. Emission limits represent worst case emissions for cold start-ups. Emissions for warm and hot start-ups are

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expected to be lower.

5. Opacity emission limits are one minute block averages.

6. Emission limits are one hour block averages and apply throughout the operating range, including during start-

up and shutdown. Emissions are based on manufacturer’s certifications using gaseous testing procedures in accordance

with 40 CFR Part 89. VOC emissions are assumed to be equivalent to NMHC emissions. In accordance with the

calculations found at 40 CFR 89.424 for No. 2 diesel fuel oil exhaust, NMHC mass emissions are calculated by

assuming that each carbon atom is accompanied (using a weighted average) by 1.8 atoms of hydrogen (i.e. NMHC as

CH1.8), which corresponds to a gas density of 0.5746 kg/m3.

7. Facility emissions include the two CTG/HRSG pairs with duct burners (EU1 and EU2), the auxiliary boiler

(EU3), the emergency diesel engine/generator set (EU4), the fire pump engine (EU5), and the auxiliary cooling tower.

Emissions, except CO emissions, for each of EU1 and EU2 are based on 8,040 hours of natural gas firing per 12

month rolling period at 100% load and 50ºF ambient temperature with no duct burner firing (2,130 MMBtu/hr,

HHV) or evaporative cooling, and 720 hours of natural gas firing per 12 month rolling period at peak load

(approximately 102% load) and 90ºF ambient temperature with 100% duct burner firing (2,449 MMBtu/hr, HHV)

and evaporative cooling, and include start-up and shutdown emissions. Worst case CO emissions for each of EU1 and

EU2 are based on a typical annual operating scenario of 3,272 hours at full load and different seasonal emission rates

depending on heat input rates, ambient temperatures, and duct burner/evaporative cooling status, and 36, 166, and 4

cold, warm, and hot start-up/shutdown cycles, respectively. Emissions for EU3 are based on 6,570 hours of natural gas

firing per 12 month rolling period at 100% load (80 MMBtu/hr, HHV). Emissions for each of EU4 and EU5 are

based on restricted operation of 300 hours per unit, including maintenance and periodic readiness testing, while firing

ULSD having a sulfur content that does not exceed 0.0015% by weight. Worst case NOx and VOC emissions for EU4

are assumed to be emitted at the EPA Tier 2 limit of 6.4 gm/KW-hr and the EPA Tier 1 limit of 1.3 gm/KW-hr,

respectively. Worst case NOx and VOC emissions for EU5 are assumed to be emitted at the EPA Tier 3 limit of 4.0

gm/KW-hr and the EPA Tier 1 limit of 1.3 gm/KW-hr, respectively. EPA Tier 1, 2, and 3 emission standards are

published in the United States Code of Federal Regulations, Title 40, Part 89 [40 CFR Part 89]. There are no NH3

emissions from the auxiliary boiler, emergency engine/generator set, fire pump engine, and auxiliary cooling tower.

The auxiliary cooling tower contributes to PM/PM10/PM2.5 emissions only based on 8,760 hours of operation per 12

month rolling period.

8. Emission limit is for the sum of filterable and condensable particulates, including sulfates.

9. Maximum fuel (natural gas only) heat input for each CTG/HRSG with duct burner is based on 8,040 hours

of operation per 12 month rolling period at 100% load and 50ºF ambient temperature with no duct burner firing

(2,130 MMBtu/hr, HHV), and 720 hours of operation per 12 month rolling period at peak load (approximately 102%

load) and 90ºF ambient temperature with 100% duct burner firing (2,449 MMBtu/hr, HHV). Maximum total fuel

heat input for the auxiliary boiler is based on 6,570 hours of operation per 12 month rolling period at 100% load (80

MMBtu/hr, HHV).

10. Emission limit is based on full (base) load (100% load) ISO corrected (59 ºF, 14.7 psia, 60% humidity) heat

rate of 6,940 Btu, higher heating value, per KW-hr net electrical output to the grid.

11. Emission limit is based on full (base) load (100% load) without duct firing ISO corrected (59 ºF, 14.7 psia,

60% humidity) heat rate of 6,940 Btu, higher heating value, per KW-hr net electrical output to the grid and the EPA

40 CFR Part 75 default CO2 emission factor of 118.9 lb/MMBtu. Compliance shall be determined during the initial

emissions compliance test performed within 180 days after initial firing of the EU. If the EU does not meet this

limit, then the Permittee shall remedy the EU’s failure to meet this limit, and shall not combust fuel in the EU until

the Permittee has shown compliance with this limit during a subsequent emissions compliance test.

12. Start-up and shutdown emission limits and duration are subject to revision by MassDEP based on review of

compliance testing (stack testing) data and CEMs/COMs data generated from the first year of commercial operation.

13. NOx emission limits are from 40 CFR Part 60 Subpart KKKK. Compliance with the more stringent LAER

NOx emission limits of this Plan Approval shall be deemed compliance with the NOx limits from 40 CFR Part 60

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Subpart KKKK.

14. Limit is based on an initial compliance test at full (base) (100% load) with no duct firing. Compliance

demonstration shall be made by emissions compliance testing within 180 days after initial firing of each EU.

15. Limit is based on an initial compliance test at peak load (approximately 102% load) with 100% duct firing.

Compliance demonstration shall be made by emissions compliance testing within 180 days after initial firing of each

EU.

16. Emission limit is effective 365 days after initial firing of the EU and is based on a 365 day rolling average,

net electrical output to the grid and the EPA 40 CFR Part 75 default CO2 emission factor of 118.9 lb/MMBtu. A new

365 day rolling average emission rate shall be calculated each day by calculating the arithmetic average of all hourly

emission rates for the preceding 365 days, excluding the hours in which the EU was not operating. Hourly CO2 mass

emissions (lb) shall be calculated by obtaining monitored and recorded actual hourly heat input (MMBtu) and

multiplying by the EPA 40 CFR Part 75 default CO2 emission factor of 118.9 lb/MMBtu.

17. Minimum Emissions Compliance Load (MECL) for EU1 and EU2 shall be a function of ambient

temperature and other system parameters.

18. MECL for EU3 shall be determined during the initial emissions compliance testing to be performed within

180 days after initial firing of EU3.

Table 7 Key:

EU# = Emission Unit Number

No. = Number

NOx = Nitrogen Oxides

CO = Carbon Monoxide

VOC = Volatile Organic Compounds

NMHC = Non-Methane Hydrocarbons

S = Sulfur

SO2 = Sulfur Dioxide

PM = Total Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in diameter

PM2.5 = Particulate Matter less than or equal to 2.5 microns in diameter

NH3 = Ammonia

H2SO4 = Sulfuric Acid

Pb = Lead

HAP = Hazardous Air Pollutants

CO2 = Carbon Dioxide

CO2e = Greenhouse Gases expressed as Carbon Dioxide equivalent and calculated by multiplying each of the six

greenhouse gases (Carbon Dioxide, Nitrous Oxide, methane, Hydrofluorocarbons, Perfluorocarbons, Sulfur

Hexafluoride) mass amount of emissions, in tons per year, by the gas’s associated global warming potential

published at Table A-1 of 40 CFR Part 98, Subpart A and summing the six resultant values.

lb = pounds

lb/hr = pounds per hour

MMBtu = million British thermal units, higher heating value (HHV) basis

lb/MMBtu = pounds per million British thermal units

ppmvd @ 15% O2 = parts per million by volume, dry basis, corrected to 15 percent oxygen

ppmvd @ 3% O2 = parts per million by volume, dry basis, corrected to 3 percent oxygen

scf = standard cubic feet

kg/m3 = kilograms per cubic meter

% = percent

gm/KW-hr = grams per Kilowatt-hour

lb/MW-hr = pounds per Megawatt-hour net electrical output to the grid

Btu/KW-hr = British thermal units per Kilowatt-hour net electrical output to the grid

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TPY = tons per 12-month rolling period

ºF = degrees Fahrenheit

psia = pounds per square inch, absolute

EPA = Unites States Environmental Protection Agency

CFR = Code of Federal Regulations

ISO = International Organization for Standardization

CTG/HRSG = combustion turbine generator/heat recovery steam generator

ULSD = Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015 weight percent sulfur

CEMS = Continuous Emission Monitoring Systems

COMS = Continuous Opacity Monitoring Systems

HHV = higher heating value basis

MECL = minimum emissions compliance load

< = less than

> = greater than

< = less than or equal to

> = greater than or equal to

NA = Not Applicable

B. NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Stationary Combustion Turbines/Heat Recovery Steam Generators/Duct Burners (EU1 and EU2)

The NSPS, 40 CFR Part 60 Subpart KKKK, apply to stationary combustion turbines with a

heat input rating greater than or equal to 10 MMBtu/hr, and which commenced construction,

reconstruction, or modification after February 18, 2005. The NSPS, 40 CFR Part 60 Subpart

KKKK, also apply to emissions from any associated HRSGs or duct burners, and therefore includes

both the combustion turbines and the duct burners (EU1 and EU2) at the proposed Facility.

These NSPS allow the turbine owner or operator the choice of either a concentration based

or output based NOx emission standard. The concentration based limit is expressed in units of

ppmvd @ 15% O2. The output based emission limit is expressed in units of mass emissions per unit

of useful recovered energy, nanograms per Joule (ng/J), or lb/MW-hr. The applicable NOx emission

standard for EU1 and EU2 is 15 ppmvd @ 15% O2 or 54 ng/J of useful output (0.43 lb/MW-hr).

The Permittee has ensured that the proposed Facility will comply with these limits through the use

of dry low-NOx combustion technology in conjunction with SCR add-on NOx control technology to

control NOx emissions to 2.0 ppmvd @ 15% O2 and 0.051 lb/MW-hr during natural gas firing, well

below the NSPS limits.

The NSPS for SO2 emissions are the same for all turbines regardless of size or fuel type. The

NSPS for turbines located in the continental area prohibits the discharge into the atmosphere of any

gases that contain SO2 in excess of 110 ng/J (0.90 lb/MW-hr) gross energy output. The owner or

operator of the turbine can choose to comply with either the SO2 limit or the limit on the sulfur

content of the fuel burned. For a turbine located in a continental area, the fuel sulfur content limit is

26 ng/J (0.060 lb SO2/MMBtu) heat input. The Permittee will meet the NSPS for SO2 by burning

natural gas with sulfur content not exceeding 0.5 grains sulfur per 100 standard cubic feet of gas

fired (0.0015 lb SO2/MMBtu), well below the NSPS limit.

The Permittee shall comply with all applicable emission standards, monitoring, record

keeping, and reporting requirements of 40 CFR Part 60 Subpart KKKK for EU1 and EU2.

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Auxiliary Boiler (EU3)

The NSPS, 40 CFR Part 60 Subpart Dc, apply to steam generating units for which

construction commenced after June 9, 1989, and that have a heat input rating of between 10 and 100

MMBtu/hr. Based on the design heat input rating of 80 MMBtu/hr, HHV, the NSPS, 40 CFR Part

60 Subpart Dc, apply to the natural gas fired auxiliary boiler (EU3) at the Facility. For natural gas

fired boilers, the NSPS does not impose specific emission limits.

The Permittee shall comply with all applicable monitoring, record keeping, and reporting

requirements of 40 CFR Part 60 Subpart Dc for EU3.

Emergency Engine/Generator and Fire Pump Engine (EU4 and EU5)

The emergency generator (EU4) and fire pump (EU5) engines serving the Proposed Facility

will both be subject to the NSPS under 40 CFR Part 60 Subpart IIII. The NSPS requires emergency

generator engines to meet the non-road engine emission standards identified in 40 CFR Part 89.112

and 89.113. The fire pump engine will be subject to the emission standards identified in 40 CFR

Part 60 Subpart IIII, Table 4. The NSPS require engine manufacturers to produce engines that

comply with these standards. The Permittee shall install emergency generator and fire pump engines

serving EU4 and EU5 that comply with the 40 CFR Part 60 Subpart IIII requirements.

The Permittee shall comply with all applicable emission standards, operating restrictions,

monitoring, record keeping, and reporting requirements of 40 CFR Part 60 Subpart IIII for EU4

and EU5.

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C. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS

(NESHAP) for the following Source Categories

Stationary Combustion Turbines/Heat Recovery Steam Generators/Duct Burners (EU1 and EU2)

The NESHAP at 40 CFR Part 63 Subpart YYYY apply to combustion turbines at major

sources of hazardous air pollutant (HAP) emissions. A major source of HAP emissions is a

source which has the potential to emit ten (10) or more tons per year of any single HAP, or

twenty five (25) or more tons per year of all HAPs combined. The proposed Facility is not a

major source of HAP emissions. Therefore, the proposed Facility’s combustion turbines are not

subject to the 40 CFR Part 63 Subpart YYYY requirements.

The proposed Facility’s duct burners are considered “steam electric generating units”

under the NESHAP. Steam electric generating units are regulated under 40 CFR Part 63 Subpart

UUUUU. However, the NESHAP at 40 CFR Part 63 Subpart UUUUU only apply to coal and

oil-fired steam electric generating units, and not to gas fired units such as the proposed Facility

duct burners. Therefore, the duct burners are not subject to the 40 CFR Part 63 Subpart UUUUU

requirements.

Auxiliary Boiler (EU3)

The NESHAP at 40 CFR Part 63 Subpart DDDDD for industrial, commercial, and

institutional boilers apply only to major sources of HAP emissions. However, the Facility is not a

major source of HAP emissions. Therefore, EU3 is not subject to the 40 CFR Part 63 Subpart

DDDDD requirements.

The NESHAP at 40 CFR Part 63 Subpart JJJJJJ for industrial, commercial, and

institutional boilers apply to area (or minor) sources of HAP emissions, but do not include

natural gas fired boilers. Since the auxiliary boiler shall fire natural gas only, it is not subject to

the 40 CFR Part 63 Subpart JJJJJJ requirements.

Emergency Engine/Generator and Fire Pump Engine (EU4 and EU5)

The NESHAP at 40 CFR Part 63 Subpart ZZZZ, for stationary reciprocating internal

combustion engines (RICE) apply to both major and area sources of HAP emissions, and covers

both emergency and non-emergency engines. Both EU4 and EU5 have stationary emergency

engines that are subject to 40 CFR Part 63 Subpart ZZZZ. However, for new stationary emergency

engines at area sources of HAP emissions that began construction or reconstruction after June 12,

2006, the NESHAP requirements are satisfied if the engines comply with the NSPS requirements

under 40 CFR Part 60 Subpart IIII. The Permittee shall install emergency generator and fire pump

engines serving EU4 and EU5 that comply with the 40 CFR Part 60 Subpart IIII requirements.

D. ALLOWANCES

The Permittee’s proposed Facility is subject to various emission allowance programs.

Emission allowance programs are market based air quality regulatory programs for which

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various classes of emission sources are required to obtain, secure, and/or hold a sufficient

number of “allowances” to cover actual reported emissions emanating therefrom. Allowances are

measured in “tons” of emissions (one allowance equals one ton of emissions). At specified

intervals, “true-up” occurs at which time allowances in the Permittee’s account are withdrawn to

cover actual emissions over a specified time period. The Permittee is required to hold a sufficient

number of allowances to cover reported emissions from the proposed Facility for the applicable

time period as of the “true-up” date. The true-ups are done on a facility-wide basis, for emissions

from all subject emission units at the proposed Facility. True-ups for annual SO2 and ozone

season NOx (May through September) emissions are done annually. True-up for CO2 emissions

is done every three years.

These allowance programs require that actual facility emissions of SO2, NOx, and CO2 (

see Table 7, footnote 16) be monitored, recorded, and reported pursuant to documented

monitoring plans and the regulatory provisions of 40 CFR Part 75.

Table 8 below contains the Permittee’s applicable allowance programs for each pollutant,

including the applicable regulation(s) and subject EUs at the proposed Facility covered in this

Proposed Plan Approval.

Table 8

Pollutant Program Applicable

Regulation

Subject Facility Emission

Units

SO2 Acid Rain

Program (ARP)

40 CFR Parts

72, 73, and 75

EU1, EU2

NOx NOx Ozone

Season Clean Air

Interstate Rule

(CAIR)

310 CMR 7.32 EU1, EU2

CO2 Regional

Greenhouse Gas

Initiative (RGGI)

CO2 Budget

Trading Program

(State Only

Requirement)

310 CMR 7.70 EU1, EU2

Table 8 Key:

EU = Emission Unit

ARP = Acid Rain Program

CAIR = Clean Air Interstate Rule

RGGI = Regional Greenhouse Gas Initiative

CFR = Code of Federal Regulations

CMR = Code of Massachusetts Regulations

SO2 = Sulfur Dioxide

NOx = Nitrogen Oxides

CO2 = Carbon Dioxide

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The Permittee shall submit to MassDEP:

1. A Phase II Acid Rain Permit Application at least 24 months prior to commencement of

commercial operation of any subject emission unit;

2. A CAIR Permit Application at least 18 months prior to commencement of commercial

operation of any subject emission unit; and,

3. A CO2 Budget Emission Control Plan (ECP) at least 12 months prior to commencement

of commercial operation of any subject emission unit.

E. COMPLIANCE DEMONSTRATION

The proposed Facility is subject to, and the Permittee shall ensure that the proposed

Facility shall comply with, the monitoring, testing, record keeping, and reporting requirements as

contained in Tables 9, 10, and 11 below:

Table 9

EU# Monitoring and Testing Requirements

EU1,

EU2, EU3

1. The Permittee shall ensure that the proposed Facility is constructed to accommodate the

emissions (compliance) testing requirements as stipulated in 40 CFR Part 60 Appendix A. The

two outlet sampling ports (90 degrees apart from each other) for each emission unit must be

located at a minimum of one duct diameter upstream and two duct diameters downstream of

any flow disturbance. In addition, the Permittee shall facilitate access to the sampling ports and

testing equipment by constructing platforms, ladders, or other necessary equipment.

2. The Permittee shall ensure that compliance testing of the proposed Facility is completed

within 180 days after initial firing of each EU to demonstrate compliance with the emission

limits specified in Table 7 of this Proposed Plan Approval. All emissions testing shall be

conducted in accordance with MassDEP’s “Guidelines for Source Emissions Testing” and in

accordance with EPA reference test methods as specified in 40 CFR Part 60, Appendix A, 40

CFR Part 60 Subpart KKKK, 40 CFR Parts 72 and 75, or by another method which has been

approved in writing by MassDEP. The Permittee shall schedule the compliance testing such that

MassDEP personnel can witness it.

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Table 9

EU# Monitoring and Testing Requirements

EU1,

EU2, EU3

3. The Permittee shall conduct initial compliance tests of the proposed Facility to document

actual emissions of EU1, EU2, and EU3 so as to determine their compliance status versus the

emission limits (in lb/hr, lb/MMBtu, ppmvd, and lb/MW-hr, as applicable) in Table 7 for the

pollutants listed below.

Testing for these pollutants for EU1 and EU2 as specified below shall be conducted at four (4)

load conditions that cover the entire normal operating range: the minimum emissions

compliance load (MECL); 75 percent load; 100 percent (base) load without duct firing; and

peak (approximately 102 percent load) with 100 percent duct firing.

NOx, CO, VOC, SO2, PM, PM10, PM2.5, NH3, CO2, H2SO4, opacity

Testing for these pollutants for EU3 as specified below shall be conducted at four (4) load

conditions that cover the entire normal operating range: the MECL (to be determined during the

compliance test); 50 percent load; 75 percent load; and 100 percent load.

NOx, CO, VOC, SO2, PM, PM10, PM2.5, H2SO4, opacity

4. The above referenced emissions testing shall include testing to develop a correlation

between CO and VOC emissions for EU1 and EU2; parametric monitoring testing for PM,

PM10, and PM2.5 emissions for EU1 and EU2; and NOx/CO emissions optimization testing

for EU3.

5. The Permittee shall conduct NOx/CO optimization on, and tune, EU3 according to

procedures contained in EPA 340/1-83-023 “Combustion Efficiency Optimization Manual

for Operators of Oil and Gas Fired Boilers” with the goal of reducing air pollutant emissions

to optimum levels. In addition, the Permittee shall tune EU3 in accordance with said

procedures and inspect and maintain EU3 per manufacturer recommendations as well as test

EU3 for efficient operation on an annual basis. The Permittee shall allow MassDEP

personnel to witness tuning of EU3 if and when requested by MassDEP.

6. The Permittee shall install, calibrate, test, and operate a Data Acquisition and Handling

System(s) (DAHS), CEMS, and COMS serving EU1 and EU2 to measure and record the

following emissions:

a) O2; b) NOx; c) CO; e) NH3; d) opacity.

The Permittee shall install, calibrate, test, and operate a DAHS and COMS to measure and

record opacity on EU3.

7. The Permittee shall ensure that all emission monitors and recorders serving EU1, EU2 and

EU3 comply with MassDEP approved performance and location specifications, and conform

with the EPA monitoring specifications at 40 CFR 60.13 and 40 CFR Part 60 Appendices B

and F, and all applicable portions of 40 CFR Parts 72 and 75, 310 CMR 7.32, and 310 CMR

7.70, as applicable.

8. The Permittee shall ensure that the subject CEMS and COMS are equipped with properly

operated and properly maintained audible and visible alarms to activate whenever emissions

from the Facility exceed the limits established in Table 7 of this Plan Approval.

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Table 9

EU# Monitoring and Testing Requirements

EU1,

EU2, EU3

9. The Permittee shall operate each CEMS and/or COMS serving EU1, EU2 and EU3 at all

times except for periods of CEMS and COMS calibration checks, zero and span adjustments,

preventative maintenance, and periods of unavoidable malfunction.

10. The Permittee shall obtain and record emissions data from each CEMS and/or COMS

serving EU1, EU2 and EU3 for at least seventy (75) percent of each emission unit’s

operating hours per day, for at least seventy five (75) percent of each emission unit’s

operating hours per month, and for at least ninety five (95) percent of each emission unit’s

operating hours per quarter, except for periods of CEMS and COMS calibration checks, zero

and span adjustments, and preventive maintenance.

11. All periods of excess emissions occurring at the Facility, even if attributable to an

emergency/malfunction, start-up/shutdown or equipment cleaning, shall be quantified and

included by the Permittee in the compilation of emissions and determination of compliance

with the emission limits as stated in Table 7 of this Plan Approval. (“Excess Emissions” are

defined as emissions which are in excess of the emission limits as stated in Table 7). An

exceedance of emission limits in Table 7 due to an emergency or malfunction shall not be

deemed a federally permitted release as that term is used in 42 U.S.C. Section 9601(10).

12. The Permittee shall use and maintain its CEMS and/or COMS serving EU1, EU2 and

EU3 as “direct-compliance” monitors to measure NOx, CO, NH3, O2, and/or opacity.

“Direct-compliance” monitors generate data that legally documents the compliance status of

a source.

13. The Permittee shall develop a quality assurance/quality control (QA/QC) program for the

long-term operation of the CEMS and/or COMS serving EU1, EU2 and EU3 so as to

conform with 40 CFR Part 60 Appendices B and F, all applicable portions of 40 CFR Parts

72 and 75, 310 CMR 7.32, and 310 CMR 7.70.

14. The Permittee shall install, operate, and maintain a fuel metering device and recorder for

EU1, EU2 and EU3 that records natural gas consumption in standard cubic feet (scf).

15. The Permittee shall monitor fuel heat input rate (MMBtu/hr, HHV) and total fuel heat

input (MMBtu) for EU1, EU2, and EU3.

16. The Permittee shall monitor each date and daily hours of operation and total hours of

operation for EU1, EU2, and EU3 per month and twelve month rolling period.

EU1, EU2 17. The Permittee shall ensure that initial compliance tests of the proposed Facility are

conducted for “hot start”, “warm start”, “cold start”, and shutdown periods as defined in the

Permittee’s Application for EU1 and EU2. These compliance tests shall represent periods of

operation below the MECL for EU1 and EU2. Emission data generated from this testing

shall be made available for review by MassDEP prior to determining and approving the

maximum allowable emission limits for all pollutants listed in Table 7 (lb per event) and

opacity limits, for these periods of time. MassDEP will incorporate these emission limits into

a Final Plan Approval for the as-built Facility upon issuance and such limits shall be

considered enforceable.

18. Whenever either combustion turbine is operating below the MECL for start-up and

shutdown, the VOC emissions shall be considered as occurring at the rate determined in the

most recent compliance test for start-up/shutdown conditions.

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Table 9

EU# Monitoring and Testing Requirements

EU1, EU2 19. If either combustion turbine is operating at the MECL or greater, and if its CO emissions

are below the CO emission limit at the given combustion turbine operating conditions, its

VOC emissions shall be considered as meeting the emission limits contained in this

Proposed Plan Approval, subject to correlation as contained in Condition 20 below.

20. If either combustion turbine is operating at the MECL or greater, and if its CO emissions

are above the CO emission limit at the given combustion turbine operating conditions, its

VOC emissions shall be considered as occurring at a rate determined by the equation:

VOCactual = VOClimit x (COactual/COlimit), pending the outcome of compliance testing, after

which a VOC/CO correlation curve for each combustion turbine will be developed and used

for VOC compliance determination purposes.

21. The Permittee shall monitor the natural gas consumption of EU1 and EU2 in accordance

with 40 CFR Part 60 Subpart KKKK utilizing a continuous monitoring system accurate to +

5 percent, and as approved by MassDEP.

22. The Permittee shall monitor the sulfur content of the natural gas combusted by EU1 and

EU2 in accordance with 40 CFR Part 60 Subpart KKKK, or pursuant to any alternative fuel

monitoring schedule issued in accordance with 40 CFR Part 60 Subpart KKKK.

23. The Permittee shall install and operate continuous monitors fitted with alarms to monitor

continuously the temperatures at the inlets to the SCR and CO catalysts serving EU1 and

EU2. In addition, the Permittee shall monitor the combustion turbine inlet and ambient

temperatures for EU1 and EU2.

24. The Permittee shall install and operate high and low level audible alarm monitors on the

NH3 storage tank and shall ensure that they are properly maintained.

25. The Permittee shall monitor the load, start-up and shutdown duration, and mass

emissions (lb/event) during start-up and shutdown periods of EU1 and EU2.

26. The Permittee shall monitor the operation of EU1 and EU2, in accordance with the

surrogate methodology or parametric monitoring developed during the most recent

compliance test concerning PM, PM10, and PM2.5 emission limits.

27. The Permittee shall monitor the SO2 and CO2 emissions in accordance with 40 CFR Part

75.

28. The Permittee shall monitor the Greenhouse Gas emission rate utilizing the calculation

procedures in 40 CFR Part 98 Subpart A, Table A-1.

29. The Permittee shall continuously monitor the net electrical output to the grid of the

proposed Facility.

EU4, EU5 30. The Permittee shall equip, operate, and maintain non-resettable hour meters on the

emergency generator and fire pump engines in order to monitor the hours of operation of

each emission unit.

31. The Permittee shall monitor the quantity and sulfur content of ULSD fuel oil burned in

EU4 and EU5.

Facility-

Wide

32. The Permittee shall monitor all operations to ensure sufficient information is available to

comply with 310 CMR 7.12 Source Registration.

33. If and when MassDEP requires it, the Permittee shall conduct compliance testing in

accordance with EPA Reference Test Methods and 310 CMR 7.13.

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Table 9 Key:

EU# = Emission Unit Number

EPA = United States Environmental Protection Agency

CFR = Code of Federal Regulations

CMR = Code of Massachusetts Regulations

DAHS = Data Acquisition and Handling System

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

SCR = Selective Catalytic Reduction

QA/QC = Quality Assurance/Quality Control

O2 = Oxygen

NOx = Nitrogen Oxides

CO = Carbon Monoxide

NH3 = Ammonia

PM = Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in size

PM2.5 = Particulate Matter less than or equal to 2.5 microns in size

VOC = Volatile Organic Compounds

CO2 = Carbon Dioxide

SO2 = Sulfur Dioxide

H2SO4 = Sulfuric Acid

lb = pounds

lb/hr = pounds per hour

lb/MMBtu = pounds per million British thermal units

ppmvd = parts per million by volume, dry basis

lb/MW-hr = pounds per MW-hr net electrical output to the grid

scf = standard cubic feet

MMBtu/hr = million British thermal units per hour

MMBtu = million British thermal units

HHV = higher heating value basis

MECL = Minimum Emissions Compliance Load

ULSD = Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015weight percent sulfur

Table 10

EU# Record Keeping Requirements

EU1,

EU2, EU3

1. The Permittee shall maintain records of each emission unit’s hourly fuel heat input rate

(MMBtu/hr, HHV), total fuel heat input (MMBtu), and natural gas consumption (scf) per

month and twelve month rolling period basis.

2. The Permittee shall maintain records of each date and daily hours of operation and total

hours of operation of each EU per month and twelve month rolling period.

3. The Permittee shall maintain on-site permanent records of output from all continuous

monitors (including CEMS and COMS) for flue gas emissions and natural gas consumption

(scf).

4. The Permittee shall maintain a log to record problems, upsets or failures associated with

the subject emission control systems, DAHS, CEMS, and/or COMS serving EU1, EU2, and

EU3, and the NH3 handling system serving EU1 and EU2.

EU1, EU2 5. The Permittee shall continuously estimate and record VOC emissions on the DAHS using the

CO/VOC correlation curve developed from the most recent compliance test.

6. The Permittee shall continuously estimate and record PM, PM10, and PM2.5 emissions on the

DAHS using the surrogate methodology or parametric monitoring derived from the most recent

compliance test.

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Table 10

EU# Record Keeping Requirements

EU1, EU2 7. The Permittee shall maintain records of the load, start-up and shutdown duration, and

mass emissions (lb/event) during start-up and shutdown periods of EU1 and EU2.

8. The Permittee shall maintain records of net electrical output to the grid from the Facility

on a daily basis.

9. The Permittee shall maintain records of the sulfur content of the natural gas combusted by

EU1 and EU2 at the frequency required pursuant to 40 CFR Part 60 Subpart KKKK, or

pursuant to any alternative fuel monitoring schedule issued in accordance with 40 CFR Part

60 Subpart KKKK.

10 The Permittee shall record SO2 and CO2 emissions from EU1 and EU2 in accordance

with 40 CFR Part 75.

11. The Permittee shall record the Greenhouse Gas emission rate of EU1 and EU2 on a daily

basis utilizing the calculation procedures in 40 CFR Part 98 Subpart A, Table A-1.

12. The Permittee shall maintain continuous records of SCR and CO control system inlet

temperatures, combustion turbine inlet temperatures and ambient temperatures.

13. The Permittee shall maintain the SOMP for the NH3 handling system serving EU1 and

EU2 in a convenient location and make them readily available to all employees.

EU3 14. The Permittee shall record and post conspicuously on or near EU3 the results of annual

inspections, maintenance, and testing and the date(s) upon which it was performed.

EU4, EU5 15. The Permittee shall maintain a record of the quantity of ULSD fuel oil combusted in, and

the total hours of operation of, EU4 and EU5 per month and per 12-month rolling period.

16. The Permittee shall maintain a record of the sulfur content of each ULSD fuel oil delivery at

the Facility.

17. The Applicant shall maintain records concerning engine certifications as described in 310

CMR 7.26 (42)(e)1. at the Facility.

Facility-

Wide

18. A record keeping system for the Facility shall be established and maintained up-to-date

by the Permittee such that year-to-date information is readily available. Record keeping

shall, at a minimum, include:

a) Compliance records sufficient to document actual emissions from the Facility in order to

determine compliance with what is allowed by this Proposed Plan Approval. Such records

shall include, but are not limited to, fuel usage rates, emissions test results, monitoring

equipment data and reports;

b) Maintenance: A record of routine maintenance activities performed on the subject

emission units’ control equipment and monitoring equipment at the Facility including, at a

minimum, the type or a description of the maintenance performed and the date(s) and time(s)

the work was commenced and completed; and,

c) Malfunctions: A record of all malfunctions on the subject emission units’ control and

monitoring equipment at the Facility including, at a minimum: the date and time the

malfunction occurred; a description of the malfunction and the corrective action taken; the

date and time corrective actions were initiated; and the date and time corrective actions were

completed.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 40 of 59

Table 10

EU# Record Keeping Requirements

Facility-

Wide

19. The Permittee shall maintain all records required by 310 CMR 7.32, 310 CMR 7.70, 310

CMR 7.71 (Reporting of Greenhouse Gas Emissions), and 40 CFR Part 98 (Mandatory

Greenhouse Gas Emissions Reporting) at the Facility.

20. The Permittee shall maintain monthly records to demonstrate the Facility’s compliance

status regarding the Facility-Wide emission limits (TPY) specified in Table 7. Records shall

include actual emissions for the month as well as for the previous 11 months. (The MassDEP

approved format can be downloaded at

http://www.mass.gov/eea/agencies/massdep/air/approvals/limited-emissions-record-keeping-

and-reporting.html#WorkbookforReportingOn-SiteRecordKeeping in Microsoft Excel

format.)

21. The Permittee shall maintain a copy of this Plan Approval, underlying Application, and

the most up-to-date Standard SOMP for each emission unit and PCD approved herein on-

site.

22. The Permittee shall maintain a complaint log concerning emissions, odor, and noise from

the Facility. The Permittee shall make available to the general public a telephone number

which receives and records complaints concerning the Facility 24 hours per day, 7 days per

week. The complaint log shall be maintained for the most recent five (5) year period. The

complaint log shall be made available to the public or MassDEP upon request. The Permittee

shall take all reasonable actions to respond to said complaints in a timely manner.

23. The Permittee shall maintain records for the annual preparation of a Source

Registration/Emission Statement Form in accordance with 310 CMR 7.12.

24. The Permittee shall maintain records of monitoring and testing as required by Table 9.

All records required by this Plan Approval shall be kept on site for five (5) years and made

available for inspection by MassDEP or EPA upon request.

Table 10 Key:

EU# = Emission Unit Number

PCD = Pollution Control Device

SOMP = Standard Operating and Maintenance Procedures

EPA = United States Environmental Protection Agency

DAHS = Data Acquisition and Handling System

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

SCR = Selective Catalytic Reduction

CFR = Code of federal Regulations

CMR = Code of Massachusetts Regulations

CO = Carbon Monoxide

NH3 = Ammonia

PM = Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in size

PM2.5 = Particulate Matter less than or equal to 2.5 microns in size

VOC = Volatile Organic Compounds

SO2 = Sulfur Dioxide

CO2 = Carbon Monoxide

ULSD = Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015weight percent sulfur

lb = pounds

scf = standard cubic feet

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 41 of 59

MMBtu/hr = million British thermal units per hour

MMBtu = million British thermal units

HHV = higher heating value basis

TPY = tons per 12-month rolling period

Table 11

EU# Reporting Requirements

EU1,

EU2, EU3

1. The Permittee must obtain written MassDEP approval of an emissions test protocol prior

to initial compliance emissions testing of EU1, EU2 and EU3 at the Facility. The protocol

shall include a detailed description of sampling port locations, sampling equipment,

sampling and analytical procedures, and operating conditions for any such emissions testing.

In addition, the protocol shall include procedures for: a) the required CO and VOC

correlation for EU1 and EU2; b) a parametric monitoring strategy to ensure continuous

monitoring of PM, PM10, and PM2.5 emission from EU1 and EU2; and c) procedures for the

required NOx and CO optimization for EU3. The protocol must be submitted to MassDEP at

least 30 days prior to commencement of testing.

2. The Permittee shall submit a final emissions test results report to MassDEP within 45 days

after completion of the initial compliance emissions testing program.

3. A QA/QC program plan for the CEMS and/or COMS serving EU1, EU2 and EU3 must be

submitted, in writing, at least 30 days prior to commencement of commercial operation of

the subject emission units. MassDEP must approve the QA/QC program prior to its

implementation. Subsequent changes to the QA/QC program plan shall be submitted to

MassDEP for MassDEP approval prior to their implementation.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 42 of 59

Table 11

EU# Reporting Requirements

EU1,

EU2, EU3

4. The Permittee shall submit a quarterly Excess Emissions Report to MassDEP by the

thirtieth (30th) day of April, July, October, and January covering the previous calendar periods

of January through March, April through June, July through September, and October through

December, respectively. The report shall contain at least the following information:

a) The Facility CEMS and COMS excess emissions data, in a format acceptable to

MassDEP.

b) For each period of all excess emissions or excursions from allowable operating conditions

for the emission unit(s), the Permittee shall list the duration, cause, the response taken, and

the amount of excess emissions. Periods of excess emissions shall include periods of start-

up, shutdown, malfunction, emergency, equipment cleaning, and upsets or failures associated

with the emission control system or CEMS or COMS. (“Malfunction” means any sudden

and unavoidable failure of air pollution control equipment or process equipment or of a process

to operate in a normal or usual manner. Failures that are caused entirely or in part by poor

maintenance, careless operation, or any other preventable upset condition or preventable

equipment breakdown shall not be considered malfunctions. “Emergency” means any

situation arising from sudden and reasonably unforeseeable events beyond the control of this

source, including acts of God, which situation would require immediate corrective action to

restore normal operation, and that causes the source to exceed a technology based limitation

under the Plan Approval, due to unavoidable increases in emissions attributable to the

emergency. An emergency shall not include noncompliance to the extent caused by improperly

designed equipment, lack of preventative maintenance, careless or improper operations,

operator error or decision to keep operating despite knowledge of these things.)

c) A tabulation of periods of operation (including dispatch) of each emission unit and total

hours of operation of each emission unit during the calendar quarter.

EU1, EU2 5. After completion of the initial compliance emissions testing program, the Permittee shall

submit information for MassDEP review that documents the actual emissions impacts

generated by EU1 and EU2 during start-up and shutdown periods versus any applicable

NAAQS and SILs or the AALs and TELs for air toxics. This information shall be submitted

to MassDEP as part of the final emissions test results report.

6. The Permittee shall submit to MassDEP, in accordance with the provisions of Regulation 310

CMR 7.02(5)(c), plans and specifications for the main exhaust stack, CTGs, the SCR control

system (including the NH3 handling and storage system), the CO catalyst control system, and

the CEMS, COMS, and DAHS once the specific information has been determined, but in any

case not later than 30 days prior to commencement of construction/installation of each

component of each subject emission unit.

EU3 7. The Permittee shall submit to MassDEP, in accordance with the provisions of Regulation 310

CMR 7.02(5)(c), the plans and specifications for the auxiliary boiler, and its Ultra Low NOx

burner, exhaust stack, COMS and DAHS once the specific information has been determined,

but in any case not later than 30 days prior to commencement of construction/installation of

each component of EU3.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 43 of 59

Table 11

EU# Reporting Requirements

EU4, EU5 8. The Permittee shall submit to MassDEP a certification for each engine in accordance with

310 CMR 7.26 (42)(e)1 not later than 30 days prior to commencement of its

construction/installation.

9. The Permittee shall submit to MassDEP, in accordance with the provisions of Regulation 310

CMR 7.02(5)(c), the plans and specifications for the emergency engine/generator set, fire pump

engine, and associated exhaust stacks once the specific information has been determined, but in

any case not later than 30 days prior to commencement of construction/installation of each

component of the subject emission unit.

Facility-

Wide

10. The Permittee shall submit to MassDEP a plan for monitoring and abating air and noise

impacts during the period of construction of the proposed Facility.

11. The Permittee shall submit, in writing, the following notifications to MassDEP within

fourteen (14) days after each occurrence:

a) date of commencement of construction of each subject emission unit at the Facility;

b) date when construction has been completed of each subject emission unit at the Facility;

c) date of initial firing of each subject emission unit at the Facility;

d) date when each subject emission unit at the Facility is either ready for commercial

operation or has commenced commercial operation.

12. The Permittee shall submit to MassDEP an Operating Permit Application in accordance

with 310 CMR 7.00: Appendix C no later than 12 months after commencement of

commercial operation of the Facility.

13. If the Facility is subject to 40 CFR Part 68, due to the presence of a regulated substance

above a threshold quantity in a process, the Permittee must submit a Risk Management Plan

no later than the date the regulated substance is first present above a threshold quantity.

14. The Permittee shall report to EPA in accordance with 40 CFR Part 75.

15. The Permittee shall comply with all applicable reporting requirements of 310 CMR 7.32,

310 CMR 7.70, 310 CMR 7.71 (Reporting of Greenhouse Gas Emissions), and 40 CFR Part 98

(Mandatory Greenhouse Gas Emissions Reporting).

16. The Permittee must notify MassDEP by telephone or fax or e-mail

[[email protected]] as soon as possible, but in any case no later than three (3)

business days after the occurrence of any upsets or malfunctions to the Facility equipment,

air pollution control equipment, or monitoring equipment which result in an excess emission

to the air and/or a condition of air pollution.

17. The Permittee shall notify MassDEP immediately by telephone or fax or e-mail

[[email protected]] and within three (3) working days, in writing, of any upset

or malfunction to the NH3 handling or delivery systems that resulted in a release or threat of

release of NH3 to the ambient air at the Facility. In addition, the Permittee must comply with

all notification procedures required under M.G.L. c. 21 E for any release or threat of release

of NH3.

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Footprint Power Salem Harbor Development LP

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Application No. NE-12-022

Page 44 of 59

Table 11

EU# Reporting Requirements

Facility-

Wide

18. The Permittee shall submit a semi-annual report to MassDEP by July 30 and January 30 of

each year to demonstrate the Facility’s compliance status regarding the Facility-Wide emission

limits (TPY) specified in Table 7. Reports shall include actual emissions for the previous 12

months. (The MassDEP approved format can be downloaded at

http://www.mass.gov/eea/agencies/massdep/air/approvals/limited-emissions-record-keeping-

and-reporting.html#WorkbookforReportingOn-SiteRecordKeeping in Microsoft Excel

format.)

19. The Permittee shall submit to MassDEP a SOMP for the subject emission units and

associated control and monitoring/recording systems at the Facility no later than 30 days

prior to commencement of commercial operation of the unit. Thereafter, the Permittee shall

submit updated versions of the SOMP to MassDEP no later than thirty (30) days prior to the

occurrence of a significant change. MassDEP must approve of significant changes to the

SOMP prior to the SOMP becoming effective. The updated SOMP shall supersede prior

versions of the SOMP.

20. The Permittee shall submit to MassDEP all information required by this Plan Approval

over the signature of a “Responsible Official” as defined in 310 CMR 7.00 and shall include

the Certification statement as provided in 310 CMR 7.01(2)(c).

21. All notifications and reporting to MassDEP required by this Plan Approval shall be made

to the attention of:

Department of Environmental Protection/Bureau of Waste Prevention

205B Lowell Street

Wilmington, Massachusetts 01887

Attn: Permit Chief

Phone: (978) 694-3200

Fax: (978) 694-3499

E-Mail: [email protected]

22. The Permittee shall report annually to MassDEP, in accordance with 310 CMR 7.12, all

information as required by the Source Registration/Emission Statement Form. The Permittee

shall note therein any minor changes (under 310 CMR 7.02(2)(e), 7.03, 7.26, etc.), which did

not require Plan Approval.

23. The Permittee shall provide a copy to MassDEP of any record required to be maintained

by this Plan Approval within thirty (30) days from MassDEP’s request.

24. The Permittee shall submit to MassDEP for approval a stack emission pretest protocol, at

least thirty (30) days prior to emission testing, for emission testing as defined in Table 9

Monitoring and Testing Requirements.

25. The Permittee shall submit to MassDEP a final stack emission test results report, within

forty five (45) days after emission testing, for emission testing as defined in Table 9

Monitoring and Testing Requirements.

Table 11 Key:

EU# = Emission Unit Number

EPA = United States Environmental Protection Agency

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 45 of 59

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

DAHS = Data Acquisition and Handling System

CFR = Code of Federal Regulations

CMR = Code of Massachusetts Regulations

M.G.L. = Massachusetts General Laws

SOMP = Standard Operating and Maintenance Procedures

QA/QC = Quality Assurance/Quality Control

CTG = Combustion Turbine Generator

SCR = Selective Catalytic Reduction

TPY = tons per 12 month rolling period

NOx = Oxides of Nitrogen

CO = Carbon Monoxide

NH3 = Ammonia

PM = Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in size

PM2.5 = Particulate Matter less than or equal to 2.5 microns in size

VOC = Volatile Organic Compounds

NAAQS = National Ambient Air Quality Standards

SILs = Significant Impact Levels

AAL = Allowable Ambient Limit

TEL = Threshold Effects Exposure Limit

6. SPECIAL REQUIREMENTS

A. SPECIAL TERMS AND CONDITIONS

The Facility is subject to, and the Permittee shall ensure that the Facility shall comply

with, the special terms and conditions as contained in Table 12 below:

Table 12

EU# Special Terms and Conditions

EU1, EU2 1. The Permittee shall not allow the combustion turbines at the Facility to operate below the

MECL, except for start-ups and shutdowns. Emissions during start-ups and shutdowns shall

be included in the TPY limits specified in Table 7.

2. The Permittee shall ensure that the SCR control equipment serving EU1 and EU2 is

operational whenever the turbine exhaust temperature at the SCR unit attains the minimum

exhaust temperature specified by the SCR vendor and other system parameters are satisfied

for SCR operation. The specific load at which this exhaust temperature and other system

parameters are achieved will vary based on ambient conditions and whether the start-up is

cold, warm, or hot.

3. The Permittee shall maintain in the Facility control room, properly maintained, operable,

portable NH3 detectors for use during an NH3 spill, or other emergency situation involving

NH3, at the Facility.

EU1, EU2,

EU3

4. The Permittee shall develop as part of the Standard Operating Procedures for EU1, EU2,

and EU3, an MECL optimization protocol to establish minimum operating load(s) that

maintain compliance with all emission limitations at various ambient temperatures and

conditions for each respective emission unit.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 46 of 59

Table 12

EU# Special Terms and Conditions

EU1, EU2,

EU3

5. The Permittee shall maintain an adequate supply of spare parts on-site to maintain the on-

line availability and data capture requirements for the CEMS and COMS equipment serving

the Facility.

Facility-

Wide

6. The Permittee shall properly train all personnel to operate the Facility and the control and

monitoring equipment serving the Facility in accordance with vendor specifications. All

persons responsible for the operation of the Facility shall sign a statement affirming that

they have read and understand the approved SOMP. Refresher training shall be given by the

Permittee to Facility personnel at least once annually.

7. Prior to commencing construction of any emission unit at the Facility, the roadways

serving said Facility shall be paved and maintained free of deposits that could result in

excessive dust emissions.

8. The Permittee shall comply with all provisions of 40 CFR Parts 72 and 75, 40 CFR Part

60, 40 CFR Part 63, 40 CFR Part 64, 40 CFR Part 68, 40 CFR Part 98, and 310 CMR 6.00

through 8.00 that are applicable to this Facility.

9. All requirements of this Approval which apply to the Permittee shall apply to all

subsequent owners and/or operators of the Facility.

Table 12 Key:

EU# = Emission Unit Number

CFR = Code of federal regulations

CMR = Code of Massachusetts Regulations

SOMP = Standard Operating and Maintenance Procedures

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

SCR = Selective Catalytic Reduction

NH3 = Ammonia

TPY = tons per 12 month rolling period

MECL = Minimum Emissions Compliance Load

B. STACK INFORMATION

The Permittee shall install, maintain, and utilize exhaust stacks with the following

parameters, as contained in Table 13 below, for the Emission Units that are regulated by this

Plan Approval:

Table 13

EU# Stack Height

Above Ground

(feet)

Stack Inside Exit

Dimensions

(feet)

Stack Gas Exit

Velocity Range

(feet per second)

Stack Gas Exit

Temperature Range

(oF)

EU1, EU2 (1)

230

(Each Flue)

20

(Each Flue)

39.2 to 61.9

(Each Flue)

175 to 215

(Each Flue)

EU3 (1)

230 3 < 70.2 < 530

EU4 86 1 < 113.3 < 620

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 47 of 59

Table 13

EU# Stack Height

Above Ground

(feet)

Stack Inside Exit

Dimensions

(feet)

Stack Gas Exit

Velocity Range

(feet per second)

Stack Gas Exit

Temperature Range

(oF)

EU5 22 0.667 < 80.6 < 820

Table 13 Notes:

1. EU1, EU2, and EU3 shall emit through one stack, containing three (3) flues.

Table 13 Key:

EU# = Emission Unit Number oF = degrees Fahrenheit

< = less than or equal to

C. NOISE (State-Only Requirement)

Daytime and nighttime sound measurements to determine ambient (background) sound

levels were taken at twelve locations (ST1 through ST12 in Table 14). Two additional

monitoring locations (R1 and R2 in Table 14) were added with data in the public record to

expand the study area and supplement the measurement data set, as collected by the Permittee.

Baseline sound measurements were taken on May 17/18, 2012 and November 20/21, 2012.

Salem Harbor Station’s existing Boiler Units 3 and 4 were not operating during the measurement

time periods. It is expected that the National Grid substation transformers will remain operating

at the site even after the existing facility has been demolished; therefore, sound measurements

included operation of these transformers. The sound measurements consisted of both A-weighted

sound levels and octave band sound levels. A-weighted sound levels emphasize the middle

frequency sounds and de-emphasize lower and higher frequency sounds, and are reported in

decibels designated as “dBA”. The A-weighted sound levels were recorded for each of the five

categories most commonly used to describe ambient environments: L90, L50, L10, Lmax, and Leq.

The L90 level represents the sound level exceeded 90 percent of the time and is used by

MassDEP for the regulation of sound emissions.

In general, background (L90) levels (in dBA) at locations ST1 through ST12 averaged from

36 to 49 during nighttime hours (with the exception of location ST9 where no nighttime

measurements were taken) and from 39 to 51 during daytime hours. To compensate for nighttime

measurements taken before midnight instead of during the typically quietest time of the day (12AM

to 4AM), the Permittee conservatively deducted 2 dBA from the measured ambient sound levels at

locations ST1, ST2, ST5, ST6, and ST8.

Calculations of operational noise impacts from the proposed Facility were calculated using

DataKustic GmbH’s CadnaA, a computer-aided noise abatement program (version 4.1.137).

CadnaA conforms to International Standard ISO-9613.2, “Acoustics – Attenuation of Sound during

Propagation Outdoors.” The method evaluated A-weighted sound pressure levels under

meteorological conditions favorable to propagation from sources of known sound emissions.

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Footprint Power Salem Harbor Development LP

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Transmittal No. X254064

Application No. NE-12-022

Page 48 of 59

The allowable sound levels generated from base load (100% load) operation of the

proposed Facility by the Permittee are summarized in Table 14 below:

Table 14

Location Ambient

(L90,dBA) (1) Facility

(L90,dBA)

Ambient and

Facility

(L90,dBA)

Increase Over

Ambient (dBA)

(2)

ST1 – Located to the

North/ Residences near

39 Fort Avenue

47 44 49 2

ST2 - Existing Property

Line to the West/Block

House

Square/Residences near

Fort Avenue and Derby

Street Intersection

42 44 46 4

ST3 – Located to the

Northeast/25 Memorial

Drive/Bentley

Elementary School

39 41 43 4

ST4 – Existing Property

Line to the

Southwest/Residences

near Intersection of

Webb Street and Derby

Street/23 Derby Street

39 43 44 5

ST5 – Existing Property

Line to the Southwest/59

Derby Street

39 44 45 6

ST6 – Located to the

East across Salem

Harbor/76 Naugus

Avenue (Marblehead)

36 34 38 2

ST7 – Located to the

East/Winter Island Park

(Harbormaster Office)

39 39 42 3

ST8 – Located to the

Northeast/Intersection of

Fort Avenue and Winter

Island Road/Winter

Island Road

38 33 39 1

ST9 – Existing Property

Line to the South/Blaney

Street Pier on Salem

Wharf

39 42 44 5

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Footprint Power Salem Harbor Development LP

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Transmittal No. X254064

Application No. NE-12-022

Page 49 of 59

Table 14

Location Ambient

(L90,dBA) (1) Facility

(L90,dBA)

Ambient and

Facility

(L90,dBA)

Increase Over

Ambient (dBA)

(2)

ST10 – Southwest

Corner of the Existing

Property/Mackey

Building/Art Gallery

36 41 42 6

ST11 – Near House of

Seven Gables across

from 41 Turner Street

39 37 41 2

ST12 – Pickering Wharf

near Victoria’s Station

approximately 100 feet

behind Sail Schooner

“Fame” Kiosk

41 32 42 1

R1 – Plummer House 40 33 41 1

R2 – Winter Island Road

Residences

34 33 38 4

Table 14 Notes:

1. The lowest existing background levels observed during either nighttime or daytime where the sound level is

exceeded 90 percent of the time (L90) which is the level regulated by MassDEP Noise Policy 90-001.

2. MassDEP Noise Policy 90-001 limits sound level increases to no more than 10 dBA over the L90 ambient

levels. Pure tone conditions or tonal sounds, defined as any octave band level which exceeds the levels in adjacent

octave bands by 3 dBA or more, are not allowed.

Table 14 Key:

L90 = sound level exceeded 90 percent of the time

dBA = decibels, A-weighted

In addition, the Permittee shall comply with the following conditions:

1. The Facility shall be operated and maintained such that at all times:

a) No condition of air pollution shall be caused by sound as provided in 310 CMR

7.01.

b) No sound emissions resulting in noise shall occur as provided in 310 CMR 7.10

and MassDEP’s Noise Policy 90-001. MassDEP’s Noise Policy 90-001 limits increases

over the existing L90 background level to 10 dBA. Additionally, "pure tone" sounds,

defined as any octave band level which exceeds the levels in adjacent octave bands by 3

dBA or more, are also prohibited. The Permittee, at a minimum, shall ensure that the

Facility complies with said Policy.

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Footprint Power Salem Harbor Development LP

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Transmittal No. X254064

Application No. NE-12-022

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2. Facility personnel shall continue to identify and evaluate all plant equipment that may cause

a noise condition. Sources of noise include, but are not limited to: main exhaust stack containing

three flues, ACC, CTG packages, combustion turbine air inlets, STG packages, HRSG packages,

CTG step up transformers, STG step up transformers, screw type natural gas compressor, natural

gas metering station, auxiliary boiler, and auxiliary cooling tower.

3. The Permittee shall perform the following measures or equivalent alternative measures at

the proposed Facility as noise mitigation as indicated in (and in addition to) the Application and the

Permittee’s responses, dated April 12, June 10, and June 18, 2013, to MassDEP’s requests for

additional information with regard to noise mitigation:

a) Enclose the CTG, low noise HRSG, and STG packages for EU1 and EU2 within

acoustically treated buildings consisting of absorptive double layer acoustic walls

constructed of steel skin, mineral wool, and perforated metal interior designed for a

Sound Transmission Class (STC) rating of 46. All ventilation openings and rooftop fans

shall be acoustically silenced and attenuated. Machinery and personnel access into the

buildings shall be through high performance acoustic doors.

b) Enclose the natural gas compressor and metering station within an acoustically

treated building with airways into the building and exhausts adequately sound attenuated

through the use of silencers.

c) Install GE 12 foot Silencers with Acoustic Plenums on combustion turbine inlet air

filter houses for EU1 and EU2.

d) Install turbine exhaust silencers in the HRSG discharge flow paths, either in the

connecting ducts and/or in the vertical stack flues for EU1, EU2, and EU3 designed to meet

a total sound power attenuation of 22 dBA and a 90-degree directional sound power level of

83 dbA or less at stack exits.

e) Install ultra low noise CTG and STG step up transformers providing sound power

levels (Lw) of 83 dBA for CTG step-up transformers and 90 dBA for STG step up

transformers on EU1 and EU2, and enclose the transformers with firewalls/barriers to

provide shielding to the receptors located on Derby Street to the west and the residential area

to the south.

f) Install ACC with low noise fans and Acoustic Louvers on the inlet of the ACC,

which shall be designed to meet 51 dbA or less at 400 feet from the ACC.

g) Install a retaining wall and berm surrounding the majority of the Facility site.

These noise mitigation measures, which result in a maximum increase of 6 dbA above ambient as

shown in Table 14, are identified as Option 2 noise mitigation measures in the Permittee’s June 18,

2013 Supplement to the Application amongst the four (4) options evaluated by the Permittee as

compared to the reference (or standard) design noise mitigation measures for this type of facility.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 51 of 59

4. The Permittee shall complete a sound survey in accordance with MassDEP

procedures/guidelines within one hundred eighty (180) days after the Facility commences

commercial operation, while the Facility is in operation, to verify compliance with the allowable

sound levels specified in Table 14 of this Plan Approval. Prior to conducting the sound survey,

the Permittee shall submit in writing to MassDEP for review a sound survey protocol at least

thirty (30) days prior to commencing the sound survey. The Permittee shall submit to MassDEP

a written report, describing the results of the required sound survey, within 45 days after its

completion.

D. CONSTRUCTION REQUIREMENTS

Construction of the Facility will result in temporary increases in sound levels near the site.

The construction process will require the use of equipment that will be audible from off site

locations during certain time periods. Facility construction consists of site clearing, excavation,

foundation work, steel erection, mechanical work, and finishing work. Work on these phases will

overlap. Pile driving, generally considered the loudest construction activity, may also be required

during the excavation phase to provide proper structural support for the combustion turbine building

foundation. No blasting would be performed on site. Construction of the Facility is expected to

begin in June 2014 and continue for a period of approximately 23 months.

In order to minimize construction noise impacts, the Permittee shall, at minimum, install and

maintain a non-retractable temporary sound wall, 12 feet in height, constructed of ¾ inch Medium

Density Overlay (MD) plywood, or other material of equivalent utility and appearance, having a

surface weight of 2 pounds per square foot or greater. These specifications are based upon a Sound

Transmission Class of STC 30, or greater, per American Society for Testing and Materials (ASTM)

Test Method E90, having glass fiber, mineral wool, or other similar type sound absorptive surface

material at least 2 inches thick on the side facing the site with a Noise Reduction Coefficient rating

of NRC-0.85, or greater, per ASTM Test Method C423. When the barrier units are joined together,

the mating surfaces of the barrier sides are flush with each other and gaps between barrier units and

the bottom edges of the barrier panels and the ground are closed with material of sufficient density

to attenuate sound. The Permittee shall install and maintain in good repair said temporary noise

barrier, or equivalent, throughout the duration of the construction of the Facility.

In addition, the Permittee shall comply with the following conditions during the construction

phases of the Facility:

1. The Permittee shall ensure that Facility personnel take all reasonable precautions (noted

below) to minimize air pollution episodes (dust, odor, and noise):

a) Personnel shall exercise care in operating any noise generating equipment

(including mobile power equipment, power tools, etc.) at all times to minimize noise.

b) Construction vehicles transporting loose aggregate to or from the Facility shall be

covered.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 52 of 59

c) Open storage areas, piles of soil, loose aggregate, etc. shall be covered or watered

down as necessary to minimize dust emissions.

d) Any spillage of loose aggregate and dirt deposits on any public roadway, leading

to or from the Facility shall be removed by the next business day or sooner, if necessary.

(A mobile mechanical sweeper equipped with a water spray is an acceptable method to

minimize dust emissions).

e) On-site roadways/excavation areas subject to vehicular traffic shall be watered

down as necessary or treated with the application of a dust suppressant to minimize the

generation of dust.

2. The Permittee shall ensure that all contractors associated with the construction of the

Facility shall comply with MassDEP’s Clean Air Construction Initiative. The main aspects of

this program include:

a) All contractors shall use ULSD oil in diesel-powered non-road vehicles.

b) All non-road engines used on the construction site shall meet the applicable non-

road engine standard limitations per 40 CFR 89.112.

c) All contractors shall utilize the best available technology for reducing the

emission of PM and NOx for diesel-powered non-road vehicles. The best available

technology for reducing the emission of pollutants is that which has been verified by EPA

or the California Air Resources Board for use in non-road vehicles or on-road vehicles

where such technology may also be used in non-road vehicles.

d) All contractors shall turn off diesel combustion engines on construction

equipment not in active use and on dump trucks that are idling while waiting to load or

unload material for five minutes or more.

e) All contractors shall establish a staging zone for trucks that are waiting to load or

unload material at the work zone in a location where diesel emissions from the trucks will

not be noticeable to the public, and;

f) All contractors shall locate construction equipment away from sensitive receptors

such as residents and passersby, fresh air intakes to buildings, air conditioners, and

windows.

For informational purposes only, the City of Salem Code of Ordinances, Chapter 22, Section

22-1 governs construction noise, setting forth requirements on construction hours, allowable

activities, and procedures for obtaining a special variance during times when certain construction

activities are not allowed. Construction is allowed without a variance between the hours of 8:00 AM

and 5:00 PM, Mondays through Saturdays, and at other times if it does not “create a noise

disturbance across a residential property boundary”. The same restrictions are imposed on the

operation of drilling and/or blasting equipment, rock crushing machinery, pile driving or jack

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 53 of 59

hammers used in construction. Special variances can be granted by the building inspector for

construction work on Sundays or holidays with prior approval of the City Council.

7. GENERAL CONDITIONS

The Permittee is subject to, and shall comply with, the following general conditions:

A. Pursuant to 310 CMR 7.01, 7.02, 7.09 and 7.10, should any nuisance condition(s),

including but not limited to smoke, dust, odor or noise, occur as the result of the operation of the

Facility, then the Permittee shall immediately take appropriate steps including shutdown, if

necessary, to abate said nuisance condition(s).

B. If asbestos remediation/removal will occur as a result of the approved construction,

reconstruction, or alteration of this Facility, the Permittee shall ensure that all

removal/remediation of asbestos shall be done in accordance with 310 CMR 7.15 in its entirety

and 310 CMR 4.00.

C. If construction or demolition of an industrial, commercial or institutional building will

occur as a result of the approved construction, reconstruction, or alteration of this Facility, the

Permittee shall ensure that said construction or demolition shall be done in accordance with 310

CMR 7.09(2) and 310 CMR 4.00.

D. Pursuant to 310 CMR 7.01(2)(b) and 7.02(7)(b), the Permittee shall allow MassDEP

and/or EPA personnel access to the Facility, buildings, and all pertinent records for the purpose

of making inspections and surveys, collecting samples, obtaining data, and reviewing records.

E. This Plan Approval does not negate the responsibility of the Permittee to comply with

any other applicable Federal, State, or local regulations now or in the future.

F. Should there be any differences between the Application and this Plan Approval, the Plan

Approval shall govern.

G. Pursuant to 310 CMR 7.02(3)(k), MassDEP may revoke this Plan Approval if the

construction work is not commenced within two years from the date of issuance of this Plan

Approval, or if the construction work is suspended for one year or more.

H. This Plan Approval may be suspended, modified, or revoked by MassDEP if MassDEP

determines that any condition or part of this Plan Approval is being violated.

I. This Plan Approval may be modified or amended when in the opinion of MassDEP such

is necessary or appropriate to clarify the Plan Approval conditions or after consideration of a

written request by the Permittee to amend the Plan Approval conditions.

J. The Permittee shall conduct emission testing, if requested by MassDEP, in accordance

with EPA Reference Test Methods and regulation 310 CMR 7.13. If required, a pretest protocol

report shall be submitted to MassDEP at least 30 days prior to emission testing and the final test

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 54 of 59

results report shall be submitted within 45 days after emission testing.

K. Pursuant to 310 CMR 7.01(3) and 7.02(3)(f), the Permittee shall comply with all

conditions contained in this Plan Approval. Should there be any differences between provisions

contained in the General Conditions and provisions contained elsewhere in the Plan Approval,

the latter shall govern.

8. MASSACHUSETTS ENVIRONMENTAL POLICY ACT

The Facility was also subject to the requirements of the Massachusetts Environmental

Policy Act (MEPA) Massachusetts General Laws (M.G.L.) Chapter 30, Sections 61-62I and

Section 11.08 of the MEPA regulations at 301 CMR 11.00. On May 17, 2013, the Secretary of

the Executive Office of Energy and Environmental Affairs issued a certificate that the Final

Environmental Impact Report (FEIR) (EEA #14937) adequately and properly complied with the

MEPA and its implementing regulations.

9. SECTION 61 FINDINGS

MassDEP has carefully considered the Permittee’s Final Environmental Impact Report

(FEIR) prior to taking action on their Plan Approval Application. MassDEP, in issuing this

Proposed Plan Approval, requires the Permittee to use all feasible means and measures to avoid or

minimize adverse environmental impacts. Measures MassDEP deems necessary to mitigate or

prevent harm to the environment are included in the conditions of this Proposed Plan Approval.

MassDEP has made its decision under applicable law based on a balancing, where appropriate, of

environmental and socioeconomic objectives, as mandated by 301 CMR 11.01(4).

In the issuance of this Proposed Plan Approval, MassDEP has considered the reasonably

foreseeable climate change impacts, including greenhouse gas (GHG) emissions and effects as

addressed in the FEIR through the MEPA Greenhouse Gas Emissions Policy and Protocol and the

GHG emission mitigation/adaptation measures adopted by the Permittee in the FEIR as referenced

in the Secretary’s Certificate of finding on the FEIR, dated May 17, 2013 (EOEA #14937). This

finding incorporates by reference said mitigation/adaptation measures.

Pursuant to M.G.L. Chapter 30 Section 61 of the Massachusetts Environmental Policy Act,

(MEPA), 301 CMR 11.12 of the MEPA regulations, and the Secretary’s Certificate of finding on

the FEIR, MassDEP’s Section 61 Findings on the proposed Facility determining that all feasible

measures have been taken to avoid or minimize impacts to the environment are presented here as

follows.

Project Description

As described in the FEIR, the project consists of demolition of an existing coal-fired

power plant, remediation of the site, and construction of a new 630 megawatt (MW) nominal

electrical generating facility and associated infrastructure and equipment (the proposed Facility)

on a 65-acre site in Salem. The proposed Facility will be fired by natural gas and include “quick-

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 55 of 59

start" capability (ability to generate 300 MW within 30 minutes of start-up and 630 MW within

60 minutes). Use of duct-firing under summer conditions, will increase capacity by 62 MW for a

total of 692 MW. The project will have the capacity to generate 5.1 million megawatt hours

(MWh) annually. The proposed Facility will be constructed on approximately 20 acres of the

northwestern portion of site. The proposed Facility main stacks will be contained in a common

collar with a height of 230 feet.

The Permittee will operate the existing power plant until its scheduled shut down on June

1, 2014. Construction is proposed to begin in June 2014 and will extend for approximately 23

months. Demolition will include removal of all above-ground features of the existing facility,

including power plant buildings and equipment, stacks and precipitators, coal handling

equipment, storage tanks and associated appurtenances such as spill prevention berms; and

intake screen and pumphouse structures. The proposed Facility will include two quick-start

natural gas fired Combustion Turbine Generators (CTG); two STGs; two Heat Recovery Steam

Generators (HRSG), including pollution control equipment; an auxiliary steam boiler;

administrative/warehouse/shops space; a service bay; an auxiliary bay; a water treatment facility;

step-up transformers; an ammonia storage tank; two water tanks; and, air cooled condensers

(ACC). The proposed Facility is not dual-fueled and, therefore, does not have the potential to use

significant amounts of diesel fuel. It will include a diesel-fueled back-up generator and a diesel-

fueled fire pump engine.

Environmental Impact

Construction of the Facility has the potential to generate noise and dust. Operation of the

Facility will result in the emission of air pollutants including nitrogen oxides (NOx), volatile

organic compounds (VOC), and greenhouse gases (GHG).

Mitigation Measures

The project includes the following measures to avoid, minimize and mitigate impacts:

Air Pollution -

use of a high-efficiency advanced turbine combined cycle technology, emission

controls and reporting equipment to minimize all pollutants;

use of natural gas will limit emissions of PM, SO2 and HAPs compared to other

fossil fuels;

use of Dry Low NOx turbine combustors in combination with SCR will reduce

NOx emissions;

183 tons per year of NOx Emission Reduction Credits (ERC) will be obtained to

meet NSR offset requirements;

advanced combustor design, combustor practices, and use of a catalytic oxidation

system in the HRSG will reduce emissions of CO and VOCs; and,

quick start capability to minimize all pollutants associated with start-up.

GHG Emissions -

use of combined cycle natural gas turbines;

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 56 of 59

$4 million in CO2 allowances for RGGI offsets;

solar PV array with potential to offset 175 tons per year GHG emissions;

Administrative Building is designed to meet the United States Green Building

Council’s Leadership in Energy and Environmental Design (LEED) Certification

at the Platinum level and includes a green roof, geothermal heat pumps for

heating and cooling, variable volume ventilation fans, increased insulation to

minimize heat loss, lighting motion sensors, climate control and building energy

management systems, a 10% reduction for lighting power density (LPD) (and

identifies the potential for larger reductions), and water conserving fixtures that

exceed building code requirements; and

Operations Building includes a high albedo roof, geothermal heat pumps for

heating and cooling; increased insulation to minimize heat loss, daylighting,

lighting motion sensors; climate control, building energy management systems, a

10% reduction for LPD (and identifies the potential for larger reductions), a high

albedo roof, and water conserving fixtures;

the Permittee will provide a certification to the MEPA Office indicating that all of

the measures proposed to mitigate GHG emissions, or measures that will achieve

equivalent reductions (e.g. 56.5 tons per year reductions, or 29%, from

Administrative Building and Operations Building), are included in the project;

and,

a commitment to provide a GHG analysis, prepared consistent with the MEPA

GHG Policy and Protocol, for the subsequent redevelopment of the site

(regardless of whether the proposed redevelopment exceeds EIR thresholds) as

part of the NPC.

Noise -

siting of Facility equipment to maximize distance between receptors and noise-

producing equipment;

acoustical treatment of combustion and steam turbine buildings;

locating equipment within enclosures or buildings that provide noise attenuation

through layers of insulation and siding;

use of equipment silencers including a gas turbine inlet silencing package; a stack

silencing package to reduce sound pressure levels in each flue of the stack

structure, silencers on steam system vents and, as permitted by relevant codes, on

safety and relief valves that release high pressure steam;

gas turbines and steam turbines will be fully enclosed;

steam turbine insulation will be designed to provide thermal and acoustical

insulation;

large pumps in the HRSG enclosure (boiler feed pumps) will be enclosed in

additional acoustical structures as necessary;

location of piping, valving and control systems within enclosures or underground

to limit fluid transfer noise;

larger fans that operate at slower speeds and shielding of fans by cowlings or

other acoustical treatments on the ACC;

intake filter houses, transformers, fuel gas compressors and boiler feed water

pumps will be wrapped in acoustic barriers;

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 57 of 59

acoustically designed barrier walls around transformers to shield sensitive

receptors from transformer noise;

gas compressors and gas metering enclosure will be designed with acoustic

silencing; and

construction of a retaining wall and planted berm will be constructed around the

western, southern and eastern edges of the Facility to deflect sound.

Construction Period -

dust suppression methods during demolition will include pre-cleaning of larger

surfaces and structural members prior to demolition, water suppression sprays and

misting to prevent airborne particulates, and enclosure of areas to prevent the

migration of dust;

dust suppression during earth moving will include use of water trucks to wet

ground surface, stabilization of soils, and creation of wind breaks;

noise mitigation including construction hour limits, establishment and

enforcement of construction site and access road speed limits, mufflers on noise-

producing construction equipment and vehicles, siting of noisiest equipment as far

as possible from sensitive receptors, and maintenance of engine housing panels in

the closed position;

stabilized construction and exit points;

use of ultra-low sulfur diesel (ULSD) fuel (15 parts per million sulfur) in off-road

vehicles;

anti-idling measures including turning off diesel combustion engines on

construction equipment not in active use and limiting idling of dump trucks to

five minutes or less;

vehicles greater than 50 brake horsepower will have engines that meet EPA PM

emission standards or emission control technology certified by manufacturers to

meet or exceed emissions standards and emission control devices, such as diesel

oxidation catalysts (DOCs) or diesel particulate filters (DPFs), will be installed on

the exhaust system side of engine equipment;

delivery of large pieces of equipment or material will be by barge to minimize

impacts on local roadways.

Funding Responsibility

The Permittee has committed to funding all of the mitigation measures discussed in these

Section 61 findings.

Summary of Section 61 Findings

Based upon its review of the MEPA documents, the Plan Approval Application and

amendments thereof submitted to date and MassDEP’s regulations, MassDEP finds that the

terms and conditions of this Proposed Plan Approval constitute all feasible measures to avoid

damage to the environment and will minimize and mitigate such damage to the maximum extent

practicable. Implementation of the mitigation measures will occur in accordance with the terms

and conditions set forth in this Proposed Plan Approval.

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 58 of 59

10. MASSACHUSETTS ENERGY FACILITIES SITING BOARD

The Energy Facility Siting Board (EFSB) has not issued approval under M.G.L. Chapter

164, § 69J¼ of the Permittee’s Petition to construct and operate the Facility at the time of

issuance of this Proposed Plan Approval. Among other things, Section 69J¼ provides that “…no

state agency of the Commonwealth shall issue a construction permit for any such generating

facility unless the petition to construct such generating facility has been approved by [EFSB]

….”. Accordingly, MassDEP will not issue a final plan approval or PSD permit until EFSB has

issued the approval required by Section 69J¼.

11. PUBLIC PARTICIPATION

This Proposed Plan Approval is subject to a public comment period. Attached is a

Public Notice with publishing instructions. Please have the attached Public Notice published as

instructed at your expense in newspapers of general circulation in the municipalities where the

modifications are proposed. A minimum thirty (30) day public comment period will commence

with the date of publication of the Public Notice. It is in your interest to publish this Public

Notice as instructed and forward proof of publication to the attention of the Permit Chief, Bureau

of Waste Prevention, at the address shown on this letterhead to avoid delays in processing your

submittal. In addition to providing for a public comment period, MassDEP will hold a public

hearing on the Proposed Plan Approval, the details of which are stated in the attached Public

Notice.

[Remainder of Page Intentionally Left Blank]

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Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 59 of 59

Should you have any questions concerning this Plan Approval, please contact Cosmo

Buttaro by telephone at (978) 694-3281, or in writing at the letterhead address.

Sincerely,

Cosmo Buttaro

Environmental Engineer

Edward J. Braczyk

Environmental Engineer

James E. Belsky

Regional Permit Chief

Bureau of Waste Prevention

Enclosures

cc: George Lipka, Tetra Tech, 160 Federal Street, 3rd

Floor, Boston, MA 02110

Lauren A. Liss, Rubin & Rudman LLP, 50 Rowes Wharf, Boston, MA 02110

Board of Health, 120 Washington Street, 4th Floor, Salem, MA 01970

Fire Headquarters, 48 Lafayette Street, Salem, MA 01970

City Hall, 93 Washington Street, Salem, MA 01970

Board of Health, 7 Widger Road, Marblehead, MA 01945

Fire Headquarters, One Ocean Avenue, Marblehead, MA 01945

Town Hall, 188 Washington Street, Marblehead, MA 01945

Metropolitan Area Planning Council, 60 Temple Place, Boston, MA 02111

Deirdre Buckley, MEPA, Executive Office of Energy and Environmental Affairs, 100 Cambridge Street,

Suite 900, Boston, MA 02114

John Ballam, Department of Energy Resources, 100 Cambridge Street, Suite 1020, Boston, MA 02114

Department of Public Utilities, One South Station, Boston, MA 02110

Robert J. Shea and Kathryn Sedor, Energy Facilities Siting Board, One South Station, Boston, MA 02110

United States Environmental Protection Agency (EPA) – New England Regional Office,

5 Post Office Square, Suite 100, Mail Code OEP05-2, Boston, Massachusetts 02109-3912

Attn: Air Permits Program Manager

EPA: Donald Dahl (e-copy)

MassDEP/Boston: Karen Regas (e-copy), Yi Tian (e-copy)

MassDEP/WERO: Marc Simpson (e-copy)

MassDEP/CERO: Roseanna Stanley (e-copy)

MassDEP/SERO: Thomas Cushing (e-copy)

MassDEP/NERO: Marc Altobelli (e-copy & hard copy), Jim Belsky (e-copy), Ed Braczyk (e-copy),

Mary Persky (hard copy), Cosmo Buttaro (hard copy), Susan Ruch (e-copy)


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